UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q/A
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
 EXCHANGE ACT OF 1934 for the quarterly period ended September 30, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
 EXCHANGE ACT OF 1934 for the transition period
from ________ to _________
Commission file number: 1-12079
CALPINE CORPORATION
(A Delaware Corporation)
I.R.S. Employer Identification No. 77-0212977
50 West San Fernando Street
San Jose, California 95113
Telephone: (408) 995-5115
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:
305,317,613 shares of Common Stock, par value $.001 per share, outstanding on November 12, 2001
CALPINE CORPORATION AND SUBSIDIARIES
 Report on Form 10-Q/A
For the Quarter Ended September 30, 2001
INDEX

                                                                                                                           PAGE NO.
PART I - FINANCIAL INFORMATION

INTRODUCTORY NOTE......................................................................................................         3
           ITEM 1.    Financial Statements.

                      Consolidated Condensed Balance Sheets September 30, 2001 and December 31, 2000...................         4

                      Consolidated Condensed Statements of Operations For the Three and Nine Months
                      Ended September 30, 2001 and 2000................................................................         5

                      Consolidated Condensed Statements of Cash Flows For the Nine Months

                      Ended September 30, 2001 and 2000................................................................         6

                      Notes to Consolidated Condensed Financial Statements September 30, 2001..........................         7

           ITEM 2.    Management's Discussion and Analysis of Financial Condition and Results of Operations............        24

           ITEM 3.    Quantitative and Qualitative Disclosures About Market Risk.......................................        39

PART II - OTHER INFORMATION

           ITEM 1.    Legal Proceedings................................................................................        39

           ITEM 2.    Changes in Securities and Use of Proceeds........................................................        39

           ITEM 4.    Submission of Matters to a Vote of Security Holders..............................................        39

           ITEM 6.    Exhibits and Reports on Form 8-K.................................................................        39

Signatures  ...........................................................................................................        42	

2
INTRODUCTORY NOTE
None of the supplemental information included herein in any way restates the financial results contained in Calpine Corporation's consolidated condensed balance sheets, statements of operations or statements of cash flows at, and as of, September 30, 2001 that were contained in the Quarterly Report on Form 10-Q for the three and nine months ended September 30, 2001 (as the consolidated condensed statements of cash flows were amended by Calpine's Current Report on Form 8-K filed on December 20, 2001), but we have updated and elaborated upon certain notes thereto. Readers are encouraged to consult the 2000 10-K (as restated for our merger with Encal Energy Ltd. in our Current Report on Form 8-K filed on September 10, 2001) and other periodic filings we have made in 2001, as well as the complete text of this document, for background in understanding the additional information included herein.
Calpine hereby files this amended version of its Quarterly Report on Form 10-Q/A for the three and nine month periods ended September 30, 2001. The Quarterly Report on Form 10-Q for these periods was initially filed with the Securities and Exchange Commission on November 14, 2001 (the "Original Q3 10-Q"). This amended version (the "Q3 10-Q/A") is provided to elaborate upon certain disclosures contained in the Original Q3 10-Q. The accompanying disclosures were prepared in response to comments received by us from the staff of the division of Corporation Finance of the Securities and Exchange Commission as part of a review of our recent periodic filings. The accompanying disclosures are intended to supplement other periodic filings we have made in 2001.
This Q3 10-Q/A does not update all information contained in the Original Q3 10-Q. Readers are encouraged to consult Calpine's Current Reports on Form 8-K filed since the Original Q3 10-Q for information relating to events subsequent to the date of the Original Q3 10-Q.
Calpine will provide a version of this Q3 10-Q/A that is marked to show changes against the Original Q3 10-Q on the Company website at www.calpine.com under Investor Relations, Financial Reports and upon request at no charge. Please direct requests to Calpine Corporation, 50 West San Fernando Street, San Jose, California, 95113, attention: Lisa M. Bodensteiner, Assistant Secretary; telephone: (408) 995-5115.
3
 
PART I - FINANCIAL INFORMATION
ITEM 1. Financial Statements.
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
September 30, 2001 and December 31, 2000
 (in thousands, except share and per share amounts)

(unaudited)

                                                                                                    SEPTEMBER 30,    DECEMBER 31,
                                                                                                        2001            2000
                                                                                                    -------------    ------------
                                                                ASSETS

Current assets:
   Cash and cash equivalents ...................................................................    $    476,374     $    596,077
   Accounts receivable, net of allowance of $18,825 and $11,555 ................................       1,054,843          727,893
   Inventories .................................................................................          77,391           44,456
   Prepaid expense .............................................................................         237,457           27,515
   Other current assets ........................................................................         749,974           41,165
                                                                                                    ------------     ------------
      Total current assets .....................................................................       2,596,039        1,437,106
                                                                                                    ------------     ------------
Property, plant and equipment, net .............................................................      13,932,640        7,979,160
Investments in power projects ..................................................................         335,182          205,621
Project development costs ......................................................................          89,772           38,597
Notes receivable ...............................................................................         443,676          217,927
Restricted cash ................................................................................         109,193           88,618
Deferred financing costs .......................................................................         165,974          112,049
Long-term receivable ...........................................................................         271,567               --
Other assets ...................................................................................         865,241          244,125
                                                                                                    ------------     ------------
      Total assets .............................................................................    $ 18,809,284     $ 10,323,203
                                                                                                    ============     ============

                                                 LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
   Notes payable and borrowings under lines of credit, current portion .........................    $      1,120     $      1,087
   Project financing, current portion ..........................................................           1,626           58,486
   Capital lease obligation, current portion ...................................................           2,188            1,985
   Zero-Coupon Convertible Debentures Due 2021 .................................................       1,000,000               --
   Accounts payable ............................................................................       1,253,052          843,641
   Income taxes payable ........................................................................          83,821           63,409
   Accrued payroll and related expense .........................................................          55,596           53,667
   Accrued interest payable ....................................................................         120,375           77,878
   Other current liabilities ...................................................................         951,459          149,080
                                                                                                    ------------     ------------
      Total current liabilities ................................................................       3,469,237        1,249,233
                                                                                                    ------------     ------------
Notes payable and borrowings under lines of credit, net of current portion .....................         206,120          455,067
Project financing, net of current portion ......................................................       2,620,536        1,473,869
Senior notes ...................................................................................       6,300,040        2,551,750
Capital lease obligation, net of current portion ...............................................         207,149          208,876
Deferred income taxes, net .....................................................................       1,073,118          618,529
Deferred lease incentive .......................................................................          58,113           60,676
Deferred revenue ...............................................................................         102,758           92,511
Other liabilities ..............................................................................         677,789           30,529
                                                                                                    ------------     ------------
      Total liabilities ........................................................................      14,714,860        6,741,040
                                                                                                    ------------     ------------
Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts .       1,122,846        1,122,490
Minority interests .............................................................................          79,651           37,576
Stockholders' equity:
   Preferred stock, $.001 par value per share; authorized 10,000,000 shares; issued and
      outstanding one share in 2001 and 2000 ...................................................              --               --
   Common stock, $.001 par value per share; authorized 1,000,000,000 shares in 2001 and
500,000,000 shares in 2000; issued and outstanding 305,159,897
shares in 2001 and 300,074,078 shares in 2000 ..................................................             305              300
   Additional paid-in capital ..................................................................       2,018,760        1,896,987
   Retained earnings ...........................................................................       1,096,022          547,895
   Accumulated other comprehensive loss ........................................................        (223,160)         (23,085)
                                                                                                    ------------     ------------
      Total stockholders' equity ...............................................................       2,891,927        2,422,097
                                                                                                    ------------     ------------
      Total liabilities and stockholders' equity ...............................................    $ 18,809,284     $ 10,323,203
                                                                                                    ============     ============	

The accompanying notes are an integral part of these consolidated condensed financial statements.
4
 
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
For the Three and Nine Months Ended September 30, 2001 and 2000
 (in thousands, except per share amounts)

(unaudited)

                                                                             THREE MONTHS ENDED             NINE MONTHS ENDED
                                                                                SEPTEMBER 30,                 SEPTEMBER 30,
                                                                       ---------------------------     ---------------------------
                                                                          2001             2000            2001            2000
                                                                       -----------     -----------     -----------     -----------
Revenue:
  Electric generation and marketing revenue .......................    $ 2,755,603     $   643,782     $ 5,063,010     $ 1,191,461
  Oil and gas production and marketing revenue ....................        139,382          92,851         768,253         229,478
  Income from unconsolidated investments in power projects ........          6,859           7,224           9,022          21,841
  Other revenue ...................................................         14,261             957          28,444           4,388
                                                                       -----------     -----------     -----------     -----------
      Total revenue ...............................................      2,916,105         744,814       5,868,729       1,447,168
                                                                       -----------     -----------     -----------     -----------
Cost of revenue:
  Electric generation and marketing expense .......................      1,864,069         117,348       3,147,301         248,955
  Oil and gas production and marketing expense ....................         71,216          30,090         469,765          85,633
  Fuel expense ....................................................        322,100         185,619         807,544         363,315
  Depreciation expense ............................................         91,514          59,125         235,671         154,940
  Operating lease expense .........................................         27,830          25,230          83,290          46,360
  Other expense ...................................................          3,485           1,143           9,474           3,923
                                                                       -----------     -----------     -----------     -----------
      Total cost of revenue .......................................      2,380,214         418,555       4,753,045         903,126
                                                                       -----------     -----------     -----------     -----------
      Gross profit ................................................        535,891         326,259       1,115,684         544,042
Project development expense .......................................          4,894           6,091          25,105          15,074
General and administrative expense ................................         29,859          28,147         116,481          57,295
Merger expense ....................................................             --              --          41,627              --
                                                                       -----------     -----------     -----------     -----------
      Income from operations ......................................        501,138         292,021         932,471         471,673
Other expense (income):
  Interest expense ................................................         49,695          29,058         112,951          69,013
  Distributions on trust preferred securities .....................         15,385          12,650          45,947          28,713
  Interest income .................................................        (21,073)        (15,896)        (60,962)        (29,073)
  Other expense (income), net .....................................         (7,875)          1,183         (16,893)          1,439
                                                                       -----------     -----------     -----------     -----------
      Income before provision for income taxes ....................        465,006         265,026         851,428         401,581
Provision for income taxes ........................................        144,207         106,481         303,037         162,427
                                                                       -----------     -----------     -----------     -----------
      Income before extraordinary charge and cumulative effect
        of a change in accounting principle .......................        320,799         158,545         548,391         239,154
Extraordinary charge, net of tax benefit ..........................             --          (1,235)         (1,300)         (1,235)
Cumulative effect of a change in accounting principle .............             --              --           1,036              --
                                                                       -----------     -----------     -----------     -----------
       Net income .................................................    $   320,799     $   157,310     $   548,127     $   237,919
                                                                       ===========     ===========     ===========     ===========
Basic earnings per common share:
   Weighted average shares of common stock outstanding ............        304,666         285,143         302,649         275,392
   Income before extraordinary charge and cumulative effect
     of a change in accounting principle ..........................    $      1.05     $      0.56     $      1.81     $      0.87
   Extraordinary charge ...........................................    $        --     $     (0.01)    $        --     $     (0.01)
   Cumulative effect of a change in accounting principle ..........    $        --     $        --     $        --     $        --
                                                                       -----------     -----------     -----------     -----------
     Net income ...................................................    $      1.05     $      0.55     $      1.81     $      0.86
                                                                       ===========     ===========     ===========     ===========
Diluted earnings per common share:
   Weighted average shares of common stock outstanding before
     dilutive effect of certain convertible securities ............        318,552         302,239         317,880         291,705
   Income before dilutive effect of certain convertible securities,
     extraordinary charge and cumulative effect of a change in
     accounting principle .........................................    $      1.01     $      0.52     $      1.73     $      0.82
   Dilutive effect of certain convertible securities (1) ..........    $     (0.13)    $     (0.03)    $     (0.16)    $     (0.03)
                                                                       -----------     -----------     -----------     -----------
   Income before extraordinary charge and cumulative effect of a
     change in accounting principle ...............................    $      0.88     $      0.49     $      1.57     $      0.79
   Extraordinary charge ...........................................    $        --     $     (0.01)    $        --     $     (0.01)
   Cumulative effect of a change in accounting principle ..........    $        --     $        --     $        --     $        --
                                                                       -----------     -----------     -----------     -----------
     Net income ...................................................    $      0.88     $      0.48     $      1.57     $      0.78
                                                                       ===========     ===========     ===========     ===========	

(1) Includes the effect of the assumed conversion of certain convertible securities. For the three and nine months ended September 30, 2001, the assumed conversion calculation adds 58,153 and 52,353 shares of common stock and $12,470 and $33,204 to the net income results, representing the after tax expense on certain convertible securities avoided upon conversion. For the three and nine months ended September 30, 2000, the assumed conversion calculation adds 39,573 and 31,338 shares of common stock and $7,696 and $15,373 to the net income results.
The accompanying notes are an integral part of these consolidated condensed financial statements.
5
 
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2001 and 2000
 (in thousands)

(unaudited)

                                                                                        NINE MONTHS ENDED SEPTEMBER 30,
                                                                                        -------------------------------
                                                                                            2001               2000
                                                                                        ------------       ------------
Cash flows from operating activities:

   Net income ......................................................................    $   548,127        $   237,919
   Adjustments to reconcile net income to net cash provided by operating activities:
      Depreciation and amortization ................................................        242,547            160,373
      Deferred income taxes, net ...................................................        202,444             97,355
      Income from unconsolidated investments in power projects .....................         (9,022)           (21,841)
      Distributions from unconsolidated investments in power projects ..............          3,596             26,717
      Change in long-term liabilities ..............................................        459,657             (3,465)
      Minority interest ............................................................         (3,198)             2,144
      Change in operating assets and liabilities, net of effects of
       acquisitions:
      Accounts receivable ..........................................................       (561,964)          (227,017)
      Inventories ..................................................................        (30,025)            (7,579)
      Other current assets .........................................................       (890,898)            (7,151)
      Notes receivable .............................................................        (74,709)           (36,650)
      Other assets .................................................................       (627,076)             9,548
      Accounts payable and accrued expense .........................................        421,451            106,715
      Other current liabilities and deferred revenue ...............................        806,786             (1,814)
                                                                                        -----------        -----------
         Net cash provided by operating activities .................................        487,716            335,254
                                                                                        -----------        -----------
Cash flows from investing activities:
   Purchases of property, plant and equipment ......................................     (4,473,444)        (1,827,640)
   Acquisitions, net of cash acquired ..............................................     (1,303,366)          (369,036)
   Proceeds from sale and leaseback of plant .......................................             --            400,000
   Capital expenditures on joint ventures ..........................................       (103,496)          (168,234)
   Maturities of collateral securities .............................................          4,035              4,745
   Project development costs .......................................................        (55,734)            (3,689)
   Increase in notes receivable ....................................................       (140,152)           (78,383)
   Decrease (increase) in restricted cash ..........................................        (35,740)            11,988
   Other ...........................................................................          8,384            (12,505)
                                                                                        -----------        -----------
         Net cash used in investing activities .....................................     (6,099,513)        (2,042,754)
                                                                                        -----------        -----------
Cash flows from financing activities:
   Proceeds from notes payable and borrowings under lines of credit ................        141,543            929,637
   Repayments of notes payable and borrowings under lines of credit ................       (444,820)          (991,989)
   Proceeds from project financing .................................................      2,324,209            463,105
   Repayments of project financing .................................................     (1,234,776)          (579,047)
   Proceeds from issuance of senior notes ..........................................      3,853,290          1,000,000
   Repayment of senior notes .......................................................       (105,000)                --
   Proceeds from issuance of preferred securities ..................................             --            877,500
   Proceeds from issuance of convertible securities ................................      1,000,000                 --
   Proceeds from issuance of common stock ..........................................         62,283            803,812
   Financing costs .................................................................        (84,649)           (76,389)
   Write-off of deferred financing costs ...........................................             --              2,031
   Other ...........................................................................        (19,986)            12,365
                                                                                        -----------        -----------
         Net cash provided by financing activities .................................      5,492,094          2,441,025
                                                                                        -----------        -----------
Net increase (decrease) in cash and cash equivalents ...............................       (119,703)           733,525
Cash and cash equivalents, beginning of period .....................................        596,077            349,371
                                                                                        -----------        -----------
Cash and cash equivalents, end of period ...........................................    $   476,374        $ 1,082,896
                                                                                        ===========        ===========
Cash paid during the period for:
   Interest ........................................................................    $   381,772        $   154,668
   Income taxes ....................................................................    $   114,667(1)     $    41,035	

(1) Previously amended by the Company's Current Report on Form 8-K filed on December 20, 2001.
The accompanying notes are an integral part of these consolidated condensed financial statements.
6
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
 September 30, 2001
(unaudited)
1. Organization and Operation of the Company
Calpine Corporation ("Calpine"), a Delaware corporation, and subsidiaries (collectively, "the Company") is engaged in the generation of electricity in the United States, Canada and the United Kingdom. The Company is involved in the development, acquisition, ownership and operation of power generation facilities and the sale of electricity and its by-product, thermal energy, primarily in the form of steam. The Company has ownership interests in and operates gas-fired power generation and cogeneration facilities, gas fields, gathering systems and gas pipelines, geothermal steam fields and geothermal power generation facilities in the United States, Canada and the United Kingdom. Each of the generation facilities produces and markets electricity for sale to utilities and other third party purchasers. Thermal energy produced by the gas-fired cogeneration facilities is primarily sold to governmental and industrial users. Gas produced and not physically delivered to the Company's generating plants is sold to third parties.
2. Summary of Significant Accounting Policies
Basis of Interim Presentation -- The accompanying unaudited interim consolidated condensed financial statements of the Company have been prepared by the Company pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the consolidated condensed financial statements include the adjustments necessary to present fairly the information required to be set forth therein. The Company's historical amounts have been restated to reflect the pooling-of-interests transaction completed during the second quarter of 2001 for the acquisition of Encal Energy Ltd. ("Encal"). Certain information and note disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with the audited consolidated financial statements of the Company for the year ended December 31, 2000 included in the Company's September 10, 2001 Current Report on Form 8-K which gives retroactive effect to the merger with Encal. The results for interim periods are not necessarily indicative of the results for the entire year.
Use of Estimates in Preparation of Financial Statements -- The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Actual results could differ from those estimates. The most significant estimates with regard to these financial statements relate to future development costs, useful lives of the generation facilities, and depletion, depreciation and impairment of natural gas and petroleum property and equipment.
Revenue Recognition -- The Company is primarily an electric generation company, operating a portfolio of mostly wholly owned plants but also some plants in which its ownership interest is 50% or less and which are accounted for under the equity method. In conjunction with its electric generation business, the Company also produces, as a by-product, thermal energy for sale to customers, principally steam hosts at its cogeneration sites. In addition, the Company acquires and produces natural gas for its own consumption and sells the balance and small amounts of oil to third parties. To protect and enhance the profit potential of its electric generation plants, the Company, through its subsidiary, Calpine Energy Services, LP ("CES"), enters into electric and gas hedging, balancing and related transactions in which purchased electricity and gas is resold to third parties. CES acts as a principal, takes title to the commodities purchased for resale, and assumes the risks and rewards of ownership. Therefore, in accordance with Staff Accounting Bulletin No. 101 and the Emerging Issues Task Force ("EITF") Issue No. 99-19, CES recognizes revenue on a gross basis, except in the case of financial swap transactions, in which case the net gain or loss from the hedging instrument is recorded in income against the underlying hedged item when the effects of the hedged item are recognized. Hedged items typically include sales to third parties of natural gas produced, purchases of natural gas to fuel power plants, and sales of generated electricity. Finally, the Company, through Power Systems Mfg., LLC ("PSM"), designs and manufactures spare parts for gas turbines. The Company also generates small amounts of revenue by occasionally loaning funds to power projects and by providing operation and maintenance ("O&M") services to unconsolidated power plants. Further details of the Company's revenue recognition policy for each type of revenue transaction are provided below:
Electric Generation and Marketing Revenue -- This includes electricity and steam sales, gains and losses from electric power derivatives and sales of purchased power. The Company actively manages the revenue stream for its portfolio of electric
7
generating facilities. CES performs a market-based allocation of electric generation and marketing revenue to electricity and steam sales. That allocation is based on electricity delivered by the Company's electric generating facilities to serve CES contracts. As the Company actively manages the revenue stream for its portfolio of electric generation facilities, it is appropriate to review the Company's financial performance using all electric generation and marketing revenue.
Oil and Gas Production and Marketing Revenue -- This includes sales to third parties of gas, oil and related products that are produced by the Company's Calpine Natural Gas and Calpine Canada Natural Gas subsidiaries and also sales of purchased gas.
Income from Unconsolidated Investments in Power Projects -- The Company uses the equity method to recognize as revenue its pro rata share of the net income or loss of the unconsolidated investment until such time, if applicable, the Company's investment is reduced to zero, at which time equity income is generally recognized only upon receipt of cash distributions from the investee.
Other Revenue -- This includes O&M contract revenue, interest income on loans to power projects, PSM revenue from sales to third parties and miscellaneous revenue.
Energy Marketing Operations -- The Company markets energy services to utilities, wholesalers, and end users. CES provides these services by entering into contracts to purchase or supply energy, primarily, at specified delivery points and specified future dates. CES also utilizes financial instruments to manage its exposure to electricity and natural gas price fluctuations, and to a lesser degree, price fluctuations of crude oil and refined products. The Company actively manages its positions. The Company's credit risk associated with energy contracts results from the risk of loss on non-performance by counterparties. The Company reviews and assesses counterparty risk to limit any material impact on its financial position and results of operations. The Company closely monitors and manages its exposure to all of its counterparties as discussed in Note 11.
New Accounting Pronouncements -- In June 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 141, "Business Combinations", which supersedes Accounting Principles Board ("APB") Opinion No. 16, "Business Combinations" and SFAS No. 38, "Accounting for Preacquisition Contingencies of Purchased Enterprises". SFAS No. 141 eliminates the pooling-of-interests method of accounting for business combinations and modifies the recognition of intangible assets and disclosure requirements. The elimination of the pooling-of-interests method is effective for transactions initiated after June 30, 2001. The remaining provisions of SFAS No. 141 will be effective for transactions accounted for using the purchase method that are completed after June 30, 2001. The Company does not believe that SFAS No. 141 will have a material effect on its consolidated financial statements.
In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets", which supersedes APB Opinion No. 17, "Intangible Assets". SFAS No. 142 eliminates the current requirement to amortize goodwill and indefinite-lived intangible assets, extends the allowable useful lives of certain intangible assets, and requires impairment testing and recognition for goodwill and intangible assets. SFAS No. 142 will apply to goodwill and other intangible assets arising from transactions completed both before and after its effective date. The provisions of SFAS No. 142 are required to be applied starting with fiscal years beginning after December 15, 2001. The Company does not believe that SFAS No. 142 will have a material effect on its consolidated financial statements. The Company expects to have an unamortized goodwill balance at December 31, 2001 of $24.4 million, which is being amortized over periods of 10 to 20 years. The annual amortization that will be eliminated is $1.6 million.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations", which amends SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies". SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. SFAS No. 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002. The Company does not believe that SFAS No. 143 will have a material effect on its consolidated financial statements.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", which supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" and the accounting and reporting provisions of APB Opinion No. 30, "Reporting the Results of Operations -- Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions", for the disposal of a segment of a business (as previously defined in that APB Opinion). SFAS No. 144 establishes a single accounting model, based on the framework established in SFAS No. 121, for long-lived assets to be disposed of by sale. SFAS No. 144 also resolves several significant implementation issues related to SFAS No. 121, such as eliminating the requirement to allocate goodwill to long-
8
lived assets to be tested for impairment and establishing criteria to define whether a long-lived asset is held for sale. SFAS No. 144 is effective for financial statements issued for fiscal years beginning after December 15, 2001. The Company does not believe that SFAS No. 144 will have a material effect on its consolidated financial statements.
Reclassifications -- Prior period amounts in the consolidated condensed financial statements have been reclassified where necessary to conform to the 2001 presentation.
3. Property, Plant and Equipment, Net, and Capitalized Interest
Property, plant and equipment, net, consisted of the following (in thousands):

                                                   SEPTEMBER 30,    DECEMBER 31,
                                                       2001             2000
                                                   ------------     ------------

Geothermal properties .........................    $    372,282     $    334,585
Oil and gas properties ........................       2,232,865        1,441,175
Buildings, machinery and equipment ............       5,157,849        1,951,250
Power sales agreements ........................         143,330          162,086
Gas contracts .................................         140,221          129,999
Other .........................................         232,376          145,877
                                                   ------------     ------------
                                                      8,278,923        4,164,972
Less: accumulated depreciation and amortization        (868,167)        (614,816)
                                                   ------------     ------------
                                                      7,410,756        3,550,156
Land ..........................................          71,964           12,578
Construction in progress ......................       6,449,920        4,416,426
                                                   ------------     ------------
Property, plant and equipment, net ............    $ 13,932,640     $  7,979,160
                                                   ============     ============	

Construction in progress is primarily attributable to gas-fired projects under construction. Upon commencement of commercial plant operation, these costs are transferred to buildings, machinery and equipment.
Capitalized Interest -- The Company capitalizes interest on capital invested in projects during the advanced stages of development and the construction period, in accordance with SFAS No. 34, as amended by SFAS No. 58. For the nine months ended September 30, 2001 and 2000, the Company recorded net interest expense of $113.0 million and $69.0 million, respectively, after capitalizing $246.3 million and $96.7 million, respectively, of interest on general corporate funds used for construction and after recording $94.9 million and $22.8 million, respectively, of interest capitalized on funds borrowed for specific construction projects. Upon commencement of commercial plant operation, capitalized interest, as a component of the total cost of the plant, is amortized over the estimated useful life of the plant. The increase in the amount of interest capitalized during the nine months ended September 30, 2001, reflects the significant increase in the Company's power plant construction program.
The Company determines which debt instruments represent a reasonable measure of the cost of financing construction assets in terms of interest cost incurred that otherwise could have been avoided. These debt instruments and associated interest cost are included in the calculation of the weighted average interest rate used for capitalizing interest on general funds. The primary debt instruments included in the rate calculation are the Senior Notes and the $400 million corporate revolver. The capitalization rate for general corporate funds excludes the Zero-Coupon Convertible Debentures, capital lease obligations, bridge financings for acquisition purposes, cross-border financings not used for construction purposes and other borrowings used for operating purposes.
4. Notes Receivable
As of September 30, 2001 and December 31, 2000, the components of notes receivable were (in thousands):

                                              SEPTEMBER 30,      DECEMBER 31,
                                                   2001             2000
                                                ---------         ---------
PG&E note ..............................        $ 105,630         $  62,336
Delta note .............................          271,759           112,050
Metcalf note ...........................           30,176                --
Other ..................................           46,634            43,724
                                                ---------         ---------
         Total notes receivable ........          454,199           218,110
Less: Notes receivable, current portion           (10,523)             (183)
                                                ---------         ---------
Notes receivable, net of current portion        $ 443,676         $ 217,927
                                                =========         =========	

9
Calpine Gilroy Cogen, LP ("Gilroy") had a long-term power purchase agreement ("PPA") with Pacific Gas and Electric Company ("PG&E") for the sale of energy through 2018. The terms of the PPA provided for 120 megawatts of firm capacity and up to 10 megawatts of as-delivered capacity. On December 2, 1999, the California Public Utilities Commission approved the restructuring of the PPA between Gilroy and PG&E. Under the terms of the restructuring, PG&E and Gilroy are each released from performance under the PPA effective November 1, 2002. Under the restructured contract, in addition to the normal capacity revenue for the period, Gilroy will earn from September 1999 to October 2002 restructured capacity revenue it would have earned over the November 2002 through March 2018 time period, for which PG&E issues notes to the Company. These notes will be paid by PG&E during the period from February 2003 to September 2014.
In 1999, the Company, together with Bechtel Enterprises ("Bechtel"), began the development of an 880-megawatt gas-fired cogeneration project in Pittsburg, California. As part of this joint venture, the Company has an interest bearing note from the project, Delta Energy Center, LLC.
In 1999, the Company, together with Bechtel, began the development of a 579-megawatt gas-fired cogeneration project in San Jose, California. As part of this joint venture, the Company has an interest bearing note from the project, Metcalf Energy Center, LLC.
See Note 15 for a discussion of the Company's purchase of Bechtel's interests in the Delta, Metcalf and Russell City Energy Centers.
5. Acquisitions and Asset Purchases
On July 10, 2001, the Company acquired the 500-megawatt natural gas-fired, combined-cycle Otay Mesa Generating Project in San Diego County from the PG&E National Energy Group. Construction began in September 2001 and completion is scheduled for mid 2003. Under the terms of the sale, the Company will build, own and operate the facility, and PG&E National Energy Group will contract for up to 250 megawatts of output. The balance of the output will be sold into the California wholesale market through CES.
On August 15, 2001, the Company acquired approximately 86% of the voting stock of Michael Petroleum Corporation, a Houston, Texas-based natural gas exploration and development company, for $273.6 million and the assumption of $54.5 million of debt. The acquisition includes 204 billion cubic feet equivalent of proven natural gas reserves currently producing 43 mmcfe per day and an inventory of drilling locations within a 94,000 acreage position in close proximity to the South Texas Magic Valley and Hidalgo Energy Centers. See Note 15 for a discussion of the Company's purchase of the remaining interest in Michael Petroleum Corporation.
On August 24, 2001, the Company acquired and assumed operations of the Saltend Energy Centre, a 1,200-megawatt natural gas-fired power plant located at Saltend near Hull, Yorkshire, England. The Company purchased the cogeneration facility from an affiliate of Entergy Corporation for L562.5 million (US$814.4 million at exchange rates at the closing of the acquisition). The Saltend Energy Centre began commercial operation in November 2000 and is one of the largest natural gas-fired electric power generating facilities in England. Saltend provides electricity and steam for BP Chemicals' Hull Works plant under the terms of a 15-year agreement. The balance of the plant's output is sold into the deregulated United Kingdom power market.
On September 12, 2001, the Company purchased the remaining 33.3% interests in the 247-megawatt Hog Bayou Energy Center and the 213-megawatt Pine Bluff Energy Center from Houston, Texas-based Intergen (North America), Inc. for approximately $9.6 million.
On September 20, 2001, the Company's wholly owned subsidiary, Canada Power Holdings Ltd., acquired and assumed operations of two Canadian power generating facilities from British Columbia-based Westcoast Energy Inc. for C$333.1 million (US$212.1 million at exchange rates at the closing of the acquisition). The Company acquired a 100% interest in the Island Cogeneration facility, a 250-megawatt natural gas-fired electric generating facility in the commissioning phase of construction and located near Campbell River, British Columbia on Vancouver Island. This facility will provide electricity to BC Hydro under the terms of a 20-year agreement and steam to Norske Skog under the terms of a 15-year agreement. The Company also acquired a 50% interest in the 50-megawatt Whitby Cogeneration facility located in Whitby, Ontario. This facility delivers electricity to Ontario Energy Financial Corporation under the terms of a 20-year agreement and provides steam to Atlantic Packaging.
6. Financing
10
The Company drew $838.3 million on the Calpine Construction Finance Company debt revolvers during the quarter, which brought the Company's outstanding draws to $2.5 billion.
During the third quarter, the Company borrowed a total of $1.2 billion under three bridge credit facilities to finance several acquisitions (see Note 5). These facilities were refinanced with long-term Senior Notes in the fourth quarter of 2001. See Note 15 for further discussion.
7. Equity
On July 26, 2001, the Company filed amended certificates with the Delaware Secretary of State to increase the number of authorized shares of common stock to 1,000,000,000 from 500,000,000 and the number of authorized shares of Series A Participating Preferred Stock to 1,000,000 from 500,000.
8. Derivative Instruments
As an independent power producer primarily focused on generation of electricity using gas-fired turbines, our natural physical commodity position is "short" (we require) gas and "long" (we own) power capacity. To manage forward exposure to price fluctuation in these and (to a lesser extent) other commodities, we enter into derivative commodity instruments. All transactions are subject to our risk management policy which prohibits positions that exceed production capacity and fuel requirements. Any hedging, balancing or optimization activities that we engage in are directly related to our asset-based business model of owning and operating gas-fired electric power plants. We hedge exposures that arise from the ownership and operation of power plants and related sales of electricity and purchases of natural gas, and we utilize derivatives to optimize the returns we are able to achieve from these assets for our shareholders. This model is markedly different from that of companies that engage in commodity trading operations that are unrelated to underlying physical assets. Derivative commodity instruments are accounted for under the requirements of SFAS No. 133.
On January 1, 2001, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The Company currently holds five classes of derivative instruments that are impacted by the new pronouncement - interest rate swaps, forward interest rate agreements, commodity financial instruments, commodity contracts, and physical options. Additionally, one of the Company's unconsolidated investees holds two foreign exchange forward contracts.
The Company enters into various interest rate swap agreements to hedge against changes in floating interest rates on certain of its project financing facilities. The interest rate swap agreements effectively convert floating rates into fixed rates so that the Company can predict with greater assurance what its future interest costs will be and protect itself against increases in floating rates.
The Company enters into various forward interest rate agreements to hedge against interest rate fluctuations that may occur after the Company has decided to issue long-term fixed rate debt but before the debt is actually issued. The forward interest rate agreements effectively prevent the interest rates on anticipated future long-term debt from increasing beyond a certain level, allowing the Company to predict with greater assurance what its future interest costs on fixed rate long-term debt will be.
The Company enters into commodity financial instruments to convert floating or indexed electricity and gas (and to a lesser extent oil and refined product) prices to fixed prices in order to lessen its vulnerability to reductions in electric prices for the electricity it generates, to reductions in gas prices for the gas it produces, and to increases in gas prices for the fuel it consumes in its power plants. The Company seeks to "self-hedge" its gas consumption exposure to the maximum extent with its gas production position.
The Company routinely enters into commodity contracts for sales of its generated electricity and sales of its natural gas production to ensure favorable utilization of generation and production assets. Such contracts often meet the criteria of SFAS No. 133 as derivatives but are generally eligible for the normal purchase and sales exception under SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities - An Amendment of FASB Statement No. 133." For those that are not deemed normal purchases and sales, most can be designated as hedges of the underlying production of gas or electricity.
The Company also enters into physical options for short-term periods (typically one month) to balance its short-term generating position. The options, which the Company may write or purchase, typically provide for a premium component and firm price for energy when exercised.
Upon adoption of SFAS No. 133, the fair values of all derivative instruments were recorded on the balance sheet as assets or liabilities. The fair value of derivative instruments is based on present value adjusted quoted market prices of comparable contracts. For derivative instruments that were designated as hedges, the difference between the carrying values of the derivatives and their fair values at the date of adoption was recorded as a transition adjustment. At adoption, such derivatives were designated as cash flow hedges and were deemed highly effective. Accordingly, a transition adjustment was recorded to accumulated other comprehensive income ("OCI"). In the case of capacity sales contracts, a transition adjustment was recorded to earnings as a gain from the cumulative effect of a change in accounting principle.
At the end of each quarter, the changes in fair values of derivative instruments designated as cash flow hedges are recorded in OCI for the effective portion and in current earnings, using the dollar offset method, for the ineffective portion. The changes in fair values of derivative instruments designated as fair value hedges are recorded in current earnings, as are the changes in fair values of the
11
contracts being hedged. The changes in fair values of derivative instruments that are not designated as hedges are recorded in current earnings.
On June 27, 2001, the FASB cleared SFAS No. 133 Implementation Issue No. C15 dealing with a proposed electric industry normal purchases and sales exception for capacity sales transactions ("The Eligibility of Option Contracts in Electricity for the Normal Purchases and Normal Sales Exception"). On October 10, 2001, the FASB revised the criteria for qualifying for the "normal" exception. As a result of Issue No. C15, as revised, the Company expects that certain of its existing and future capacity sales contracts will qualify for the normal purchases and sales exception.
The table below reflects the amounts (in thousands) that are recorded as assets, liabilities and in OCI at September 30, 2001 for the Company's derivative instruments:

                                                                        INTEREST RATE       COMMODITY           TOTAL
                                                                         DERIVATIVE         DERIVATIVE       DERIVATIVE
                                                                         INSTRUMENTS       INSTRUMENTS       INSTRUMENTS
                                                                        ------------      ---------------   --------------

Current derivative asset (1).......................................     $         --      $       663,840   $      663,840
Long-term derivative asset (2).....................................               --              541,898          541,898
                                                                        -------------     ---------------   --------------
   Total assets....................................................     $         --      $     1,205,738   $    1,205,738
                                                                        =============     ===============   ==============
Current derivative liability (3)...................................     $      18,995     $       725,327   $      744,322
Long-term derivative liability (4).................................            56,476             600,840          657,316
                                                                        -------------     ---------------   --------------
     Total liabilities.............................................     $      75,471     $     1,326,167   $    1,401,638
                                                                        ==============    ================  ===============
Net derivative assets (liabilities)................................     $     (75,471)    $      (120,429)  $     (195,900)
                                                                        ==============    ================  ===============

Total comprehensive loss...........................................     $     (84,585)    $      (354,011)  $     (438,596)
Reclassification adjustment for activity included in net income....             9,085             122,809          131,894
                                                                        -------------     ---------------   --------------
Total pre-tax comprehensive loss from derivative instruments (5)...           (75,500)           (231,202)        (306,702)
Income tax benefit.................................................            28,300              90,842          119,142
                                                                        -------------     ---------------   --------------
     Net comprehensive loss from derivative instruments............     $     (47,200)    $      (140,360)  $     (187,560)
                                                                        =============     ===============   ==============	

(1) Included in other current assets.
(2) Included in other assets.
(3) Included in other current liabilities.
(4) Included in other liabilities.
(5) Represents total pre-tax comprehensive loss from derivatives, net of amounts recognized in earnings during 2001. This figure is disclosed in the first table in Note 9 as "Unrealized loss on cash flow hedges."
The table above presents the aggregate amounts of derivative assets, liabilities, and OCI pertaining to derivatives as of September 30, 2001. Total pre-tax comprehensive loss from derivative instruments represents the cumulative effect on the Company's accumulated OCI balance from pre-tax losses from effective cash flow hedges since the adoption of SFAS No. 133; it is not meant to be a measurement of losses for the nine months ended September 30, 2001. Because SFAS No. 133 was adopted in January 2001, the cumulative pre-tax OCI balance from effective cash flow hedges is the same as for the nine months ended September 30, 2001.
At any point in time, it is highly unlikely that total net derivative assets and liabilities will equal cumulative pre-tax OCI from derivatives, for two primary reasons:
- Earnings effect of these derivatives -- Only derivatives that qualify as effective cash flow hedges will have an offsetting amount recorded in OCI. Derivatives not so designated and the ineffective portion of derivatives designated as cash flow hedges will be recorded into earnings instead of OCI, creating a difference between net derivative assets and liabilities and pre-tax OCI from derivatives.
- Termination of effective cash flow hedges prior to maturity -- Following the termination of a cash flow hedge and subsequent settlement with a counterparty, the derivative asset or liability is liquidated and removed from the books. At this point, no asset or liability exists on the books for the hedge but a balance remains in OCI, which is amortized into earnings over the remaining original life of the hedge as long as it is probable that the forecasted transactions, or exposures that are being hedged, will occur. As a result,
12
there will be a temporary difference between OCI and derivative assets and liabilities on the books until the remaining OCI balance is fully amortized into earnings.
Below is a reconciliation from the Company's net derivative assets/liabilities to its pre-tax comprehensive loss from derivative instruments at September 30, 2001 (in thousands):

Pre-tax comprehensive loss from derivative instruments ...............    $(306,702)
Net derivative assets/(liabilities) ..................................     (195,900)
                                                                          ---------
Difference ...........................................................    $ 110,802
                                                                          =========
Reconciliation:

Pre-tax earnings impact from derivatives not designated as
  hedges and ineffective portion of derivatives designated
  as hedges ..........................................................    $ 110,662
Balances in OCI related to effective cash flow hedges terminated prior
  to maturity, net of pre-tax amortization ...........................          140
                                                                          ---------
Total reconciling items ..............................................    $ 110,802
                                                                          =========	

The asset and liability balances for the Company's commodity derivative instruments represent the net totals after offsetting certain assets against certain liabilities under the criteria of FASB Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts (an Interpretation of APB Opinion No. 10 and FASB Statement No. 105)" ("FIN 39"). For a given contract, FIN 39 will allow the offsetting of assets against liabilities so long as four criteria are met: each of the two parties under contract owes the other determinable amounts; the party reporting under the offset method has the right to set off the amount it owes against the amount owed to it by the other party; the party reporting under the offset method intends to exercise its right to set off; and; the right of set-off is enforceable by law. The table below reflects both the amounts (in thousands) recorded as assets and liabilities by the Company and the amounts that would have been recorded had the Company's commodity derivative instrument contracts not qualified for offsetting as of March 31, June 30, and September 30, 2001, respectively.

                                             MARCH 31, 2001                JUNE 30, 2001              SEPTEMBER 30, 2001
                                      --------------------------   ----------------------------  ---------------------------
                                           GROSS          NET           GROSS           NET           GROSS           NET
                                      -------------   ----------   -------------  -------------  -------------  ------------

Current Derivative Asset              $   1,000,129   $  391,291   $   2,304,337  $   1,048,198  $   2,800,765  $    663,840
Long-Term Derivative Asset                  290,237      162,488       1,359,347        874,306      1,956,502       541,898
                                      -------------   ----------   -------------  -------------  -------------  ------------
Total Derivative Assets               $   1,290,366   $  553,779   $   3,663,684  $   1,922,504  $   4,757,267  $  1,205,738
                                      =============   ==========   =============  =============  =============  ============
Current Derivative Liability          $   1,017,136   $  408,297   $   1,933,184  $     677,045  $   2,674,578  $    725,327
Long-Term Derivative Liability              314,141      186,393       1,429,490        944,448      2,203,119       600,840
                                      -------------   ----------   -------------  -------------  -------------  ------------
Total Derivative Liabilities          $   1,331,277   $  594,690   $   3,362,674  $   1,621,493  $   4,877,697  $  1,326,167
                                      =============   ==========   =============  =============  =============  ============	

The table above excludes the value of interest rate derivative instruments.
During the three and nine months ended September 30, 2001, the Company recognized gains (losses) on derivatives not designated as hedges of $13.6 million and $83.3 million, respectively, which were recorded in electric generation and marketing revenue, and $(4.1) million and $30.4 million, respectively, which were recorded in fuel expense.
During the three and nine months ended September 30, 2001, the Company recognized pre-tax gains (losses) of $49,748 and $(3.4) million, respectively, related to hedge ineffectiveness on gas and crude oil contracts, which are included in fuel expense. For the three and nine months ended September 30, 2001, the Company recognized no gains or losses related to hedge ineffectiveness on electricity contracts. During the three and nine months ended September 30, 2001, the Company excluded from the assessment of hedge effectiveness the extrinsic values of certain options used in costless collar arrangements to hedge its crude oil production. The Company recorded a gain of $2.4 million for the three and nine month periods ended September 30, 2001 associated with the extrinsic value of these options. The Company excluded no components of any other derivative instruments in assessing hedge effectiveness.
During the quarters ended March 31, 2001, June 30, 2001, and September 30, 2001, the Company's realized pre-tax commodity cash flow hedge activity contributed $17.0 million, $4.8 million, and $101.0 million to earnings respectively based on the reclassification adjustment from OCI to earnings. For the quarter ended September 30, 2001, power hedges contributed $126.9 million to earnings. At the time the power hedges were sold, the market price for the contracted delivery period was significantly higher than the market price when delivery actually occurred. For the quarter ended September 30, 2001, gas hedges reduced earnings by $25.9 million. At
13
the time the gas hedges were purchased, the market price for the contracted delivery period was significantly higher than the market price when delivery actually occurred.
As of September 30, 2001, the maximum length of time over which the Company is hedging its exposure to the variability in future cash flows for forecasted transactions is 17 years. The Company estimates that pretax gains related to the transition adjustment associated with the adoption of SFAS No. 133 of $8.5 million will be reclassified from accumulated OCI into earnings during the next three months. For derivative contracts entered into after January 1, 2001, the Company estimates that pretax gains of $87.9 million will be reclassified from accumulated OCI into earnings during the next twelve months as the hedged transactions affect earnings.
See the Form 8-K filed on September 5, 2001 for a further discussion of the Company's accounting policies related to derivative accounting.
9. Comprehensive Income
Comprehensive income is the total of net income and all other non-owner changes in equity. Comprehensive income includes net income and unrealized gains and losses from derivative instruments that qualify as hedges. The Company reports accumulated other comprehensive income (loss) in its consolidated balance sheet. In the table below, other comprehensive loss represents the total of all of the Company's components of OCI for the current year as of September 30, 2001. The Company's OCI components are: (i) unrealized pre-tax gains/losses, net of reclassification-to-earnings adjustments, from effective cash flow hedges; (ii) unrealized pre-tax gains/losses that result from the translation of foreign subsidiaries' balance sheets from the foreign functional currency (primarily Cdn.$) to the Company's consolidated reporting currency (US$); and (iii) the taxes associated with the unrealized gains/losses from items (i) and (ii). Total comprehensive income is summarized as follows (in thousands):

                                                         THREE MONTHS ENDED                  NINE MONTHS ENDED
                                                            SEPTEMBER 30,                      SEPTEMBER 30,
                                                  -------------------------------    --------------------------------
                                                        2001              2000             2001            2000
                                                  -------------      ------------    -------------      -------------
Net income.....................................   $     320,799      $    157,310    $     548,127      $     237,919
                                                  -------------      ------------    -------------      -------------
Other comprehensive income:
     Unrealized loss on cash flow hedges (1)...        (479,490)              --          (306,702)               --
     Loss on foreign currency translation......         (18,330)           (5,570)         (20,186)            (5,570)
     Income tax benefit........................         196,249             2,105          126,813              2,105
                                                  -------------      ------------    -------------      -------------
        Other comprehensive loss, net of tax...        (301,571)           (3,465)        (200,075)            (3,465)
                                                  -------------     -------------    -------------      -------------
Total comprehensive income.....................   $      19,228      $    153,845    $     348,052      $     234,454
                                                  =============      ============    =============      =============	

(1) Represents total pre-tax comprehensive loss from derivatives, net of amounts recognized in earnings, for the three and nine months ended September 30, 2001. This figure is disclosed in the first table in Note 8 as "Total pre-tax comprehensive loss from derivative instruments."
The total comprehensive income of $348.1 million for the nine months ended September 30, 2001 represents the net of the Company's net income for the period of $548.1 million and its unrealized OCI losses of $200.1 million. The accumulated other comprehensive loss of $223.2 million, as reported within Stockholders' Equity on the Company's balance sheet, is the sum of the current year's unrealized OCI loss of $200.1 million and the ending OCI balance at December 31, 2000 of $23.1 million. Prior to the current reporting year, all items affecting the Company's accumulated OCI balance resulted from the translation of its Canadian subsidiaries' balance sheets into U.S. dollars and the corresponding tax effects thereon.
Under the reporting guidance of SFAS No. 130, "Reporting Comprehensive Income," unrealized gains/losses from foreign currency translation are not viewed as deferred losses. As a result, from the total accumulated OCI loss at September 30, 2001 of $223.2 million, only the losses pertaining to cash flow hedges will be recognized in earnings in future periods. As disclosed in Note 8, these losses total $306.7 million on a pre-tax basis and $187.6 million net of tax. Below is a reconciliation of the Company's pre-tax comprehensive loss from derivatives (as disclosed in Note 8) to the accumulated other comprehensive loss at September 30, 2001 (in thousands):
14

Pre-tax comprehensive loss from derivatives ........................    $(306,702)
Accumulated other comprehensive loss ...............................     (223,160)
                                                                        ---------
Difference .........................................................    $  83,542
                                                                        =========
Reconciliation:

Less:  Accumulated other comprehensive loss at December 31, 2000 (1)    $ (23,085)

Less: Pre-tax loss on foreign currency translation from
  1/1/01 - 9/30/01 .................................................      (20,186)
Add: OCI tax benefit from unrealized loss on cash flow
  hedges from 1/1/01 - 9/30/01 (2), (3) ............................      119,142
Add: OCI tax benefit from loss on foreign currency
  translation from 1/1/01 - 9/30/01 (3) ............................        7,671
                                                                        ---------
Total Reconciling Items ............................................    $  83,542
                                                                        =========	

(1) Accumulated other comprehensive loss at December 31, 2000 is deducted because prior to January 1, 2001, there were no OCI balances related to cash flow hedges.
(2) OCI tax benefit from unrealized loss on cash flow hedges of $119,142 is disclosed in Note 8.
(3) The sum of the OCI tax benefits from unrealized loss on cash flow hedges and loss on foreign currency translation is $126,813, which is disclosed above in this Note 9.
10. Purchased Power and Gas Sales and Expense
The Company records the cost of gas consumed in its power plants as fuel expense, while gas purchased from third parties for hedging, balancing and related activities is recorded as the cost of gas purchased and resold, a component of oil and gas production and marketing expense. The Company records the actual revenue received from third parties as sales of purchased gas, a component of oil and gas production and marketing revenue.
The cost of power purchased from third parties, for hedging, balancing and optimization activities, along with the subsequent settlement of contracts that have been previously recorded in results of operations as mark-to-market gains or losses, is recorded as purchased power expense, a component of electric generation and marketing expense. The Company markets on a system basis both power generated by its plants in excess of amounts under direct contract between the plant and a third party, and power purchased from third parties.
The table below shows the relative levels and growth of purchased power sales and expense and purchased gas sales and expense activity (in thousands):

                                                THREE MONTHS ENDED                 NINE MONTHS ENDED
                                                   SEPTEMBER 30,                     SEPTEMBER 30,
                                          ------------------------------   -----------------------------
                                              2001             2000             2001            2000
                                          -------------   --------------   --------------  -------------
Sales of purchased power.............     $   2,028,280      $  55,525      $   3,165,078    $    96,646
Sales of purchased gas...............            56,917          9,985            412,782         26,316
                                          -------------      ---------      -------------    -----------
          Total......................     $   2,085,197      $  65,510      $   3,577,860    $   122,962
                                          =============      =========      =============    ===========
Purchased power expense..............     $   1,764,531      $  54,058      $   2,876,119    $    96,910
Purchased gas expense................            52,856          9,423            389,814         24,642
                                          -------------      ---------      -------------    -----------
         Total.......................     $   1,817,387      $  63,481      $   3,265,933    $   121,552
                                          =============      =========      =============    ===========	

The amounts shown in the final table of Note 9 above do not reflect the impact of all realized gains and losses from changes in the fair market value of mark-to-market power and gas commodities. The table below sets forth the subcategories that comprise the electric generation and marketing revenue and expense, the oil and gas production and marketing revenue and expense and the fuel expense line items of the income statement.
15

                                                                             THREE MONTHS              NINE MONTHS
                                                                                 ENDED                   ENDED
                                                                             SEPTEMBER 30,            SEPTEMBER 30,
                                                                      -------------------------  -----------------------------
                                                                           2001          2000         2001          2000
                                                                      -------------  ----------  --------------  -------------
                                                                                           (IN THOUSANDS)

ELECTRIC GENERATION AND MARKETING REVENUE

Electricity and steam revenue.....................................    $     713,746  $  588,257  $   1,814,616   $   1,094,815
Sales of purchased power..........................................        2,028,280      55,525      3,165,078          96,646
Mark to market gains/(losses) on power derivatives................           13,577         --          83,316             --
                                                                      -------------  ----------  -------------   ------------
                                                                      $   2,755,603  $  643,782  $   5,063,010   $   1,191,461
                                                                      =============  ==========  =============   =============
OIL AND GAS PRODUCTION AND MARKETING REVENUE

Oil and gas sales to third parties................................    $      82,465  $   82,866  $     355,471   $     203,162
Sales of purchased gas............................................           56,917       9,985        412,782          26,316
                                                                      -------------  ----------  -------------   -------------
                                                                      $     139,382  $   92,851  $     768,253   $     229,478
                                                                      =============  ==========  =============   =============
ELECTRIC GENERATION AND MARKETING EXPENSE

Plant operating expenses..........................................    $      94,283  $   53,151  $     248,001   $     132,754
Royalty expenses..................................................            5,255      10,139         23,181          19,291
Purchased power expense...........................................        1,764,531      54,058      2,876,119          96,910
                                                                      -------------  ----------  -------------   -------------
                                                                      $   1,864,069  $  117,348  $   3,147,301   $     248,955
                                                                      =============  ==========  =============   =============
OIL AND GAS PRODUCTION AND MARKETING EXPENSE

Oil and gas production expenses...................................    $      18,360  $   20,667  $      79,951   $      60,991
Purchased gas expense.............................................           52,856       9,423        389,814          24,642
                                                                      -------------  ----------  -------------   -------------
                                                                      $      71,216  $   30,090  $     469,765   $      85,633
                                                                      =============  ==========  =============   =============
FUEL EXPENSE

Cost of oil and natural gas burned by power plants................    $     318,046  $  185,619  $     834,486   $     363,315
Mark to market (gain)/loss on natural gas derivatives.............            4,054         --         (26,942)            --
                                                                      -------------  ----------  -------------   ------------
                                                                      $     322,100  $  185,619  $     807,544   $     363,315
                                                                      =============  ==========  =============   =============	

11. Significant Customers
The Company's significant customers at September 30, 2001 were certain subsidiaries of Enron Corp. ("Enron") and PG&E.
Enron
In 2001 the Company, primarily through its CES subsidiary, has transacted a significant volume of business with units of Enron. Most of these transactions are contracts for sales and purchases of power and gas for hedging and optimization purposes, some of which extend out as far as 2009. In October and November of 2001, Enron announced a series of developments including restatement of the last four years of earnings, an investigation by the Securities and Exchange Commission relating to the adequacy of Enron's disclosures of certain off-balance sheet financial transactions or structures and dismissals of certain members of senior management. On December 2, 2001, Enron Corp. and certain of its subsidiaries filed voluntary petitions for Chapter 11 reorganization with The U.S. Bankruptcy Court for the Southern District of New York.
For the three and nine months ended September 30, 2001, $767.9 million or 26.3%, and $1,329.8 million or 22.7%, of the Company's revenue was with Enron subsidiaries, primarily Enron Power Marketing, Inc. ("EPMI") and Enron North America Corp. ("ENA"). ENA is the parent corporation of EPMI. Enron is the direct parent corporation of ENA. EPMI and ENA are among the subsidiaries of Enron that filed for reorganization on December 2, 2001. The Company, primarily CES, purchases significant amounts of fuel and power from ENA and EPMI, giving rise to current accounts payable and open contract fair value positions. These purchases must be included in an overall understanding of the Company's Enron exposure. For the three months ended September 30, 2001, CES had fuel and power purchases from ENA and EPMI of $905.3 million. For the nine months ended September 30, 2001, CES had fuel and power purchases from ENA and EPMI of $1,358.7 million. The sales to and purchases from various Enron subsidiaries are mostly hedging and optimization transactions, and in most cases the purchases and sales are not related and should not be netted to try to gauge the profitability of transactions with Enron subsidiaries.
The following table sets forth information regarding the Company's transactions with Enron for the three and nine month periods ended September 30, 2001 (in thousands of dollars and thousands of MWh's, in the case of electricity transactions, and thousands of mmBTU's, in the case of oil and gas transactions):
16

                                                          THREE MONTHS                  NINE MONTHS
                                                              ENDED                        ENDED
                                                        SEPTEMBER 30, 2001           SEPTEMBER 30, 2001
                                                    -------------------------     ------------------------

                                                      DOLLAR          VOLUME       DOLLAR           VOLUME
                                                    ----------        -------     ---------         ------

Electric generation and marketing revenue
  (E&S revenues and sales of purchased power)       $  742,464         6,428      $1,155,736        11,293
Oil and gas production & marketing
  Revenue (non-affiliated sales of
  purchased gas) .............................          22,833         7,825         169,758        26,048
Other revenue ................................           2,580                         4,275
                                                    ----------                    ----------
Total power and fuel revenue from Enron ......      $  767,877                    $1,329,769
                                                    ==========                    ==========
Electric generation and marketing expense
  (Purchased power expense) ..................      $  856,823         7,080      $1,222,025        10,481
Fuel expense (cost of oil and natural gas
  burned by power plants) and mark to market
  (gain)/loss on natural gas derivatives (cost
  of gas purchased & resold) .................          48,451        10,100         136,652        18,380
                                                    ----------                    ----------
Total CES power and fuel expenses
  related to Enron(1) ........................      $  905,274                    $1,358,677
                                                    ==========                    ==========	

(1) Expenses of CES only, as other Enron expenses incurred are not material.
Unrealized pre-tax losses on derivatives designated as effective cash flow hedges that were recorded in OCI associated with Enron activity at the quarters ended March 31, 2001, June 30, 2001, and September 30, 2001 were $26.0 million, $15.9 million, and $185.0 million, respectively. Recognized gains on derivatives not designated as hedges associated with Enron activity were $39.9 million, $226.7 million and $108.5 million for the quarters ended March 31, 2001, June 30, 2001 and September 30, 2001, respectively. Recognized losses on derivatives not designated as hedges associated with Enron activity were $40.2 million, $213.8 million and $140.2 million for the quarters ended March 31, 2001, June 30, 2001 and September 30, 2001, respectively. Recognized gross gains (losses) on fair value hedges (which are perfectly offset by the gains and losses on the hedged items) associated with Enron activity were $0.0 million, $(74.3) million and $50.4 million dollars for the quarters ended March 31, 2001, June 30, 2001 and September 30, 2001, respectively. As of September 30, 2001, all of Calpine's fair value hedges are 100% effective, so there is no net earnings impact from these transactions.
On November 14, 2001, CES, ENA and EPMI entered into a Master Netting, Setoff and Security Agreement (the "Netting Agreement"). The Netting Agreement permits CES, on the one hand, and ENA and EPMI, on the other hand, to set off amounts owed to each other under an ISDA Master Agreement between CES and ENA, an Enfolio Master Firm Purchase/Sale Agreement between CES and ENA and a Master Energy Purchase/Sale Agreement between CES and EPMI (in each case, after giving effect to the netting provisions contained in each of these agreements).
Pursuant to the Netting Agreement, Enron's bankruptcy constituted an event of default, and CES effected an early termination of the ISDA Master Agreement, the Enfolio Master Agreement and the Master Energy Agreement on December 10, 2001. CES is presently determining its losses, damages, attorneys' fees and other expenses arising from the default by Enron and its affiliates, as it is entitled to do pursuant to the underlying documents. The Company expects that there will be a net amount payable to ENA pursuant to these agreements after giving effect to the Netting Agreement, and thus that there will be no net credit exposure to Enron and its affiliates arising from these transactions. The Company filed a copy of the Netting Agreement as an exhibit to a Current Report on Form 8-K dated November 14, 2001 and filed on January 16, 2002.
The Company believes that the Netting Agreement is enforceable in accordance with its terms, based upon the following analysis, although there can be no assurance in this regard. Section 553 of the Bankruptcy Code preserves the right of a creditor who owes a debt to the debtor to offset that debt against a debt owed by the debtor to the creditor, to the extent that such a right was in existence between the parties prior to the bankruptcy. Setoff rights will be preserved in bankruptcy, in general, where four conditions are met: (1) the creditor has a claim against the debtor that arose before the bankruptcy case was filed (a pre-petition claim); (2) the creditor owes a debt to the debtor that also arose pre-petition;
17
(3) the claim and debt are mutual, meaning that the identical entities or individual parties must each owe the other a debt in the same capacity; and (4) the claim and debt are each valid and enforceable.
The Bankruptcy Code expressly permits the non-debtor party to certain types of contracts, such as swap contracts and forward contracts, to terminate and liquidate the contracts after the commencement of a bankruptcy case as the result of a bankruptcy default. Section 556 provides, among other things, that the contractual right of a forward contract merchant to cause the liquidation of a forward contract pursuant to a bankruptcy termination clause will not be stayed, avoided or otherwise limited by operation of any provision of the Bankruptcy Code or by the order of any court in any proceeding under the Bankruptcy Code. Similarly, Section 560 provides, among other things, that the contractual right of any swap participant to cause the termination of a swap agreement pursuant to a bankruptcy termination clause or to offset or net out any termination values or payment amounts under or in connection with a swap agreement shall not be stayed, avoided or otherwise limited by operation of any provision of the Bankruptcy Code or by order of a court or administrative agency in any proceeding under the Bankruptcy Code. Section 362(b)(6) of the Bankruptcy Code authorizes the setoff of any mutual debts and claims arising from forward contracts and securities contracts between a debtor and a non-debtor, and 362(b)(17) of any mutual debts arising from one or more swap agreements between a debtor and a non-debtor. Finally, "swap agreement" is defined by Section 101(53B)(C) of the Bankruptcy Code to include any master agreement relating to derivative instruments of the nature identified in that section (which includes commodity derivatives).
The Company believes that the netting of debts and claims across the underlying master agreements and the transactions entered into pursuant to the master agreements, as provided for in the Netting Agreement, is entitled to the benefits of the provisions of the Bankruptcy Code summarized above although there can be no assurance in this regard. This conclusion is based not only on the language of the relevant statutory provisions, but also the policy underlying their adoption, which was to preserve the ability of counterparties to derivative contracts to immediately net and close out their contracts in the event of a bankruptcy. This is viewed as a beneficial way to mitigate systemic risk that could otherwise arise in a bankruptcy where the presence of the automatic stay, as well as the bankruptcy trustee's broad equitable powers with respect to executory contracts, would cast significant doubt upon the ongoing enforceability of derivative transactions. Separate and apart from these special protections provided by the Bankruptcy Code for forward contracts and swap agreements, the Netting Agreement and the netting provisions of the underlying master agreements are formal written agreements that would in any event be enforceable. The setoffs made by CES are often referred to as "triangular setoffs". A triangular setoff is one where A seeks to offset an obligation it owes to B against a debt that B owes to C. Here, a triangular setoff is one where CES seeks to set off an obligation it owes to ENA against a debt that EPMI owes to CES or, put another way, one where CES seeks to require the Enron entities to aggregate their debts and claims for setoff purposes. While the strict mutuality of Section 553 of the Bankruptcy Code is not present, if the parties all agree in a pre-petition contract that a setoff may be taken between A, B and C, then the agreement may be enforced in bankruptcy to the extent that it is enforceable under applicable nonbankruptcy law. This exception is limited, however, to cases where there is a formal pre-petition contract, such as the Netting Agreement.
In addition to the written Netting Agreement, for nearly a year prior to the bankruptcy filing by Enron and certain of its affiliates, CES and the Enron entities offset and netted debts and claims under all of the forward contracts and swap agreements among the parties pursuant to an oral agreement that was relied upon. It is established that the "formal contract" required to establish the right of setoff under the Bankruptcy Code need not be in writing, so long as there is sufficient evidence indicating a definite understanding or agreement between the debtor and the corporation seeking a setoff.
In assessing its exposure to Enron subsidiaries and affiliates, the Company analyzes its accounts receivable and accounts payable balances on contracts that have already settled and also the fair value (mark to market value) of the contracts that have not settled. Following are the accounts receivable and accounts payable balances, presented on both a gross and net basis, as well as the gross and net fair values of the open contracts with Enron subsidiaries and affiliates at November 29, 2001, which have been updated since the Form 8-K dated November 28, 2001 and filed on December 3, 2001. The positive net positions have realization exposure, while the negative net positions are existing or potential obligations.
18

                                                             NET                                         NET OPEN
                              GROSS          GROSS       RECEIVABLE    GROSS FAIR      GROSS FAIR        POSITIONS
                            RECEIVABLE      PAYABLE       (PAYABLE)     VALUE(+)         VALUE(-)          VALUE          TOTAL
                            ----------      -------      ----------    ----------      -----------       ---------      ---------
Enron North America .        $   15.5      $  (16.6)      $   (1.1)     $1,803.1       $(2,105.0)        $ (301.9)      $ (303.0)
Enron Power Marketing           121.1         (96.7)          24.4         451.5          (328.6)           122.9          147.3
                             --------      --------       --------      --------        --------         --------       --------
  Total .............           136.6        (113.3)          23.3       2,254.6        (2,433.6)          (179.0)        (155.7)
Enron Canada ........             1.9            --            1.9            --           (18.5)           (18.5)         (16.6)
Citrus Trading Corp .              --          (1.8)          (1.8)         32.0              --             32.0           30.2
Other ...............              --          (0.4)          (0.4)           --              --               --           (0.4)	

After netting the receivables and payables and the value of the open positions from ENA and EPMI, CES has an existing or future obligation of $155.7 million (the sum of the net receivable of $23.3 million and the net open positions value of $(179.0) million) as of November 29, 2001, which obligation will be offset by CES' losses, damages, attorneys' fees and other expenses arising from the default by Enron. The Company has one contract to purchase gas from Citrus Trading Corp ("Citrus"). El Paso Corporation, which owns 50% of Citrus, has affirmed its commitment to continue all deliveries of gas to Citrus. As further assurance, El Paso also stated it has the first option to purchase the remaining 50% of Citrus from Enron in the event Enron chooses to sell its share of Citrus. Currently, Citrus has continued to deliver all gas as required under the contract. The Company's Auburndale entity is the beneficiary of a guarantee by El Paso of 50% of Citrus' payment obligations under the Citrus fuel supply contract with Auburndale.
Based on the above, the Company had no net exposure to Enron at November 29, 2001. Additionally, the Company believes that its Citrus Trading Corp. exposure is mitigated by the fact that its parent, Citrus Corp., is 50% owned by El Paso Corporation. The Company has not established any reserve against Enron exposure.
The Company's treasury department includes a credit group focused on monitoring and managing counterparty risk. The credit group monitors the net exposure with each counterparty on a daily basis. The analysis is performed on a mark to market basis using the forward curves audited by the Company's Risk Controls group. The net exposure is compared against a counterparty credit risk threshold which is determined based on the counterparty's credit ratings, evaluation of the financial statements and bond values. The credit department monitors these thresholds to determine the need for additional collateral or an adjustment to activity with the counterparty.
The Company will continue to evaluate the Enron risk in the same manner as discussed above. The Company will adjust its threshold for Enron exposure based on factors discussed above and will continue to monitor the exposure on a daily basis.
PG&E
The Company's northern California Qualifying Facility ("QF") subsidiaries sell power to PG&E under the terms of long-term contracts at eleven facilities. On April 6, 2001, PG&E filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. PG&E is the regulated subsidiary of PG&E Corporation, and the information on PG&E disclosed below excludes PG&E Corporation's non-regulated subsidiary activity. The Company has transactions with certain of the non-regulated subsidiaries, which have not been affected by PG&E's bankruptcy. On July 12, 2001, the U.S. Bankruptcy Court for the Northern District of California approved the agreement the Company had entered into with PG&E to modify and assume all of Calpine's QF contracts with PG&E. Under the terms of the agreement, the Company will continue to receive its contractual capacity payments plus a five-year fixed energy price component that averages 5.37 cents per kilowatt-hour in lieu of the short run avoided cost. In addition, all past due receivables under the QF contracts were elevated to administrative priority status and will be paid to the Company, with interest, upon the effective date of a confirmed plan of reorganization. On September 20, 2001, PG&E filed its proposed plan of reorganization with the bankruptcy court.
The Company's QF contracts with PG&E provide that the California Public Utilities Commission ("CPUC") has the authority to determine the appropriate utility "avoided cost" to be used to set energy payments for certain QF contracts, including those for all of the Company's QF plants in California which sell power to PG&E. Section 390 of the California Public Utility Code provides QFs the option to elect to receive energy payments based on the California Power Exchange ("PX") market clearing price. In mid 2000, the Company's QF facilities elected this option and were paid based upon the PX zonal day ahead clearing price ("PX Price") from summer 2000 until January 19, 2001, when the PX ceased operating a day ahead market. Since that time, the CPUC has ordered that the price to be paid for energy deliveries by QFs electing the PX Price shall be based on a natural gas cost-based "transition formula." The CPUC has conducted proceedings (R.99-11-022) to determine whether the PX Price was the appropriate price for the energy component upon which to base payments to QFs which had elected the PX-based pricing option. The CPUC has issued a proposed decision to the effect that the PX price was the appropriate price for energy payments under the California Public Utility Code. However, a final decision has not been issued to date. Therefore, it is possible that the CPUC could order a payment adjustment based
19
on a different energy price determination. The Company believes that the PX Price was the appropriate price for energy payments, but there can be no assurance that this will be the outcome of the CPUC proceedings.
On March 28, 2001, the CPUC issued an order (Decision 01-03-067) (the "March 2001 Decision") proposing to change, on a prospective basis, the composition of the short run avoided cost ("SRAC") energy price formula, which is reset monthly, used by the California utilities in QF contracts. Prior to the March 2001 Decision, CPUC regulations calculated SRAC based on 50% Topock and 50% Malin border gas indices. In the March 2001 Decision, the CPUC changed this formulation to eliminate the prices at Topock from the SRAC formula. The March 2001 Decision is subject to challenges at the CPUC and the Federal Energy Regulatory Commission ("FERC").
On June 14, 2001, however, the CPUC issued an order (Decision 01-06-015) (the "June 2001 Decision") that authorized the California utilities, including PG&E, to amend QF contracts to elect a fixed energy price component that averages 5.37 cents per kilowatt-hour for a five-year term under those contracts in lieu of using the SRAC energy price formula. By this order, the CPUC authorized the QF contract energy price amendments without further CPUC concurrence. As part of the agreement the Company entered into with PG&E pursuant to which PG&E, in bankruptcy, agreed to assume its QF contracts with Calpine, PG&E agreed with the Company to amend these contracts to adopt the fixed price component that averages 5.37 cents pursuant to the June 2001 Decision. This election became effective as of July 16, 2001. As a result of the June 2001 Decision and the Company's agreement with PG&E to amend the QF contracts to adopt the fixed price energy component, the energy price component in Calpine's QF contracts is now fixed for five years and the Company is no longer subject to any uncertainty that may have existed with respect to this component of Calpine's QF contract pricing as a result of the March 2001 Decision. Further, the March 2001 Decision has no bearing on PG&E's agreement with the Company to assume the QF contracts in bankruptcy or on the amount of the receivable that was so assumed.
Revenues earned from PG&E for the three and nine months ended September 30, 2001 and 2000 were as follows (in thousands):

               THREE MONTHS ENDED SEPTEMBER 30,      NINE MONTHS ENDED SEPTEMBER 30,
               --------------------------------      -------------------------------
                 2001                    2000          2001                   2000
               --------                --------      --------               --------
Revenues:
PG&E ....      $159,052                $203,894      $449,047               $342,923	

PG&E receivables at September 30, 2001, April 6, 2001 (the date of PG&E's bankruptcy filing), and December 31, 2000, were as follows (in thousands):

                  SEPTEMBER 30, 2001      APRIL 6, 2001      DECEMBER 31, 2000
                  ------------------      -------------      -----------------
Receivables:
PG&E........           $292,055              $265,588             $204,448	

Of the $292.1 million PG&E receivable balance at September 30, 2001, the pre-petition balance of $265.6 million remains unreserved and is classified as a long-term receivable. Through September 30, 2001, as a result of PG&E's decision to assume its QF contracts with Calpine, the Company has recorded $6.0 million of interest income which is included in the long-term receivable balance. PG&E has paid and continues to pay currently for energy deliveries made after April 6, 2001.
The Company had a combined accounts receivable balance of $20.5 million as of September 30, 2001 from the California Independent System Operator Corporation ("CAISO") and Automated Power Exchange, Inc. ("APX"). Of this balance, $10.0 million relates to past due balances prior to the PG&E bankruptcy filing. The Company has provided a full reserve for these past due receivables. CAISO's ability to pay the Company is directly impacted by PG&E's ability to pay CAISO. APX's ability to pay the Company is directly impacted by PG&E's ability to pay the PX, which in turn would pay APX for energy delivered by the Company through APX. As noted above, the PX ceased operating in January 2001. See Note 15 for an update on the FERC investigation into the California wholesale markets.
The Company also had an accounts receivable balance of $107.2 million at September 30, 2001 from the California Department of Water Resources ("DWR"). Past due accounts receivable from the California Department of Water Resources at September 30, 2001 totaled $14.4 million. This amount has been collected in full. Payment of $13.7 million for test power sales was received on November 1, 2001. Payment of $702,350 for other test power sales was received on December 10, 2001. The Company accordingly has determined that there is no reserve needed. The Company's sales to DWR are primarily pursuant to long term contracts, so the Company has not had the same degree of collectibility problems that some generators selling into the day-ahead market have experienced because of administrative and/or political issues between the CAISO and DWR.
20
12. Earnings per Share
Basic earnings per common share were computed by dividing net income by the weighted average number of common shares outstanding for the period. The dilutive effect of the potential exercise of outstanding options to purchase shares of common stock is calculated using the treasury stock method. The dilutive effect of the assumed conversion of certain convertible securities into the Company's common stock is based on the dilutive common share equivalents and the after tax distribution expense avoided upon conversion. The reconciliation of basic earnings per common share to diluted earnings per share is shown in the following table (in thousands except per share data). All share data has been adjusted to reflect the two-for-one stock split that became effective on November 14, 2000.

                                                                                 PERIODS ENDED SEPTEMBER 30,
                                                            ---------------------------------------------------------------------
                                                                           2001                                2000
                                                            ---------------------------------   ---------------------------------
                                                                NET                                 NET
                                                              INCOME      SHARES       EPS        INCOME      SHARES       EPS
                                                            ---------   ---------  ----------   ---------   ---------  ----------

THREE MONTHS:
Basic earnings per common share:
Income before extraordinary charge and cumulative
  effect of a change in accounting principle .............  $ 320,799     304,666  $     1.05   $ 158,545     285,143  $     0.56
Extraordinary charge, net of tax benefit .................         --          --          --      (1,235)         --       (0.01)
Cumulative effect of a change in accounting principle,
  net of tax .............................................         --          --          --          --          --          --
                                                            ---------   ---------  ----------   ---------   ---------  ----------
Net income ...............................................  $ 320,799     304,666  $     1.05   $ 157,310     285,143  $     0.55
                                                            ---------   ---------  ----------   ---------   ---------  ----------
Common shares issuable upon exercise of stock options
  using treasury stock method ............................                 13,886                              17,096
                                                                        ---------                           ---------
Diluted earnings per common share:
Income before dilutive effect of certain convertible
  securities, extraordinary charge and cumulative effect
  of a change in accounting principle ....................  $ 320,799     318,552  $     1.01   $ 158,545     302,239  $     0.52
Dilutive effect of certain convertible securities ........     12,470      58,153       (0.13)      7,696      39,573       (0.03)
                                                            ---------   ---------  ----------   ---------   ---------  ----------
Income before  extraordinary  charge and cumulative effect
  of a change in accounting principle ....................    333,269     376,705        0.88     166,241     341,812        0.49
Extraordinary charge, net of tax benefit .................         --          --          --      (1,235)         --       (0.01)
Cumulative effect of a change in accounting principle,
  net of tax .............................................         --          --          --          --          --          --
                                                            ---------   ---------  ----------   ---------   ---------  ----------
Net income ...............................................  $ 333,269     376,705  $     0.88   $ 165,006     341,812  $     0.48
                                                            ---------   ---------  ----------   ---------   ---------  ----------
NINE MONTHS:
Basic earnings per common share:

Income before  extraordinary  charge and cumulative
  effect of a change in accounting principle .............  $ 548,391     302,649  $     1.81   $ 239,154     275,392  $     0.87
Extraordinary charge, net of tax benefit .................     (1,300)         --          --      (1,235)         --       (0.01)
Cumulative effect of a change in accounting principle,
  net of tax .............................................      1,036          --          --          --          --          --
                                                            ---------   ---------  ----------   ---------   ---------  ----------
Net income ...............................................  $ 548,127     302,649  $     1.81   $ 237,919     275,392  $     0.86
                                                            ---------   ---------  ----------   ---------   ---------  ----------
Common shares issuable upon exercise of stock options
  using treasury stock method ............................                 15,231                              16,313
                                                                        ---------                           ---------
Diluted earnings per common share:
Income before dilutive effect of certain convertible
  securities, extraordinary charge and cumulative effect
  of a change in accounting principle ....................  $ 548,391     317,880  $     1.73   $ 239,154     291,705  $     0.82
Dilutive effect of certain convertible securities ........     33,204      52,353       (0.16)     15,373      31,338       (0.03)
                                                            ---------   ---------  ----------   ---------   ---------  ----------
Income before  extraordinary  charge and cumulative effect
  of a change in accounting principle ....................    581,595     370,233        1.57     254,527     323,043        0.79
Extraordinary charge, net of tax benefit .................     (1,300)         --          --      (1,235)         --       (0.01)
Cumulative effect of a change in accounting principle,
  net of tax .............................................      1,036          --          --          --          --          --
                                                            ---------   ---------  ----------   ---------   ---------  ----------
Net income ...............................................  $ 581,331     370,233  $     1.57   $ 253,292     323,043  $     0.78
                                                            =========   =========  ==========   =========   =========  ==========	

21
Unexercised employee stock options to purchase approximately 2,683,858 and 134,820 shares of the Company's common stock during the nine months ended September 30, 2001 and 2000, respectively, were not included in the computation of diluted shares outstanding because such inclusion would have been anti-dilutive.
13. Commitments and Contingencies
Capital Expenditures -- During the third quarter of 2001, the Company entered into commitments for 12 steam turbine generators from Siemens Westinghouse, one steam turbine generator from Fuji and three combustion turbine generators from Siemens Westinghouse. The above brought the total number of combustion and steam turbines on order to 320 with an approximate value of $9.7 billion, which includes turbines delivered to projects under construction.
Litigation -- An action was filed against Lockport Energy Associates, L.P. ("Lockport") and the New York Public Service Commission ("NYPSC") in August 1997 by New York State Electricity and Gas Company ("NYSEG") in the Federal District Court for the Northern District of New York. NYSEG requested the Court to direct NYPSC and FERC to modify contract rates to be paid to the Lockport Power Plant. In October 1997, NYPSC filed a cross-claim alleging that the FERC violated the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"), and the Federal Power Act by failing to reform the NYSEG contract that was previously approved by the NYPSC. On September 29, 2000, the New York Federal District Court dismissed NYSEG's complaint and NYPSC's cross-claim. The Court stated that FERC has no authority to alter or waive its regulations or exemptions to alter the terms of the applicable power purchase agreements and that Qualifying Facilities are entitled to the benefit of their bargain, even if at the expense of NYSEG and its ratepayers. NYSEG has filed an appeal with respect to this decision. In any event, the Company retains the right to require The Brooklyn Union Gas Company to purchase its interest in the Lockport Power Plant for $18.9 million, less equity distributions received by the Company, at any time before December 19, 2001. On October 5, 2001, the United States Court of Appeals affirmed the judgment of the federal district court and dismissed all of the claims raised by NYSEG against Lockport.
The Company is involved in various other claims and legal actions arising out of the normal course of business. The Company does not expect that the outcome of these proceedings will have a material adverse effect on the Company's financial position or results of operations.
14. Operating Segments for the Three and Nine Months Ended September 30, 2001
The Company's primary operating segments are electric generation and marketing; oil and gas production and marketing; and corporate activities and other. Electric generation and marketing includes the development, acquisition, ownership and operation of power production facilities, the sale of electricity and steam and electricity hedging and related activity. Oil and gas production and marketing includes the ownership and operation of gas fields, gathering systems and gas pipelines for internal gas consumption, third party sales and oil and gas hedging and related activity. Corporate activities and other consists primarily of financing activities, general and administrative costs and consolidating eliminations. Certain costs related to company-wide functions are allocated to each segment. However, interest on corporate debt is maintained at corporate and is not allocated to the segments. Due to the integrated nature of the business segments, estimates and judgments have been made in allocating certain revenue and expense items. The Company evaluates performance of these operating segments based upon several criteria including profits before tax.
22

                                           ELECTRIC               OIL AND GAS
                                          GENERATION              PRODUCTION               CORPORATE
                                         AND MARKETING           AND MARKETING             AND OTHER                  TOTAL
                                    ----------------------  ----------------------  -----------------------   ----------------------
                                       2001        2000        2001        2000        2001         2000         2001        2000
                                    ----------  ----------  ----------  ----------  ----------   ----------   ----------  ----------
                                                                            (IN THOUSANDS)
For the three months ended
  September 30, 2001 and 2000:
Revenues .........................  $2,765,101  $  651,336  $  155,191  $  114,635  $   (4,187)  $  (21,157)  $2,916,105  $  744,814
Income before taxes and
extraordinary charge .............     470,545     258,484      15,656      38,934     (21,195)     (32,392)     465,006     265,026
For the nine months ended
  September 30, 2001 and 2000:

Revenues .........................  $5,077,435  $1,213,857  $  869,002  $  262,849  $  (77,708)  $  (29,538)  $5,868,729  $1,447,168
Merger expense ...................          --          --      41,627          --          --           --       41,627          --
Income before taxes, extraordinary
  charge and cumulative effect of
  a change in accounting principle     776,687     414,432     187,376      66,310    (112,635)     (79,161)     851,428     401,581	

                                   ELECTRIC          OIL AND GAS
                                  GENERATION         PRODUCTION          CORPORATE
                                 AND MARKETING      AND MARKETING        AND OTHER            TOTAL
                                 -------------      -------------      -------------      -------------
                                                             (IN THOUSANDS)
Total assets:
September 30, 2001......          $ 8,454,410        $ 3,236,573        $ 7,118,301        $18,809,284	

For the three months ended September 30, 2001 and 2000, there were intersegment revenues of approximately $15.9 million and $22.1 million, respectively. For the nine months ended September 30, 2001 and 2000, there were intersegment revenues of approximately $100.8 million and $33.9 million, respectively. The elimination of these intersegment revenues, which primarily relate to the use of internally procured gas for the Company's power plants, are included in the Corporate and Other reporting segment.
15. Subsequent Events
FERC Investigation into California Wholesale Markets -- FERC ordered all sellers and buyers in wholesale power markets administered by the California ISO, as well as representatives of the State of California, to participate in a settlement conference before a FERC administrative judge. The settlement discussions were intended to resolve all issues that remain outstanding to resolve past accounts, including sellers' claims for unpaid invoices, and buyers' claims for refunds of alleged overcharges, for past periods. The settlement discussions began on June 25, 2001, and ended on July 9, 2001. The Chief Administrative Law Judge issued his report and recommendations to FERC on July 12, 2001. On July 25, 2001, FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California. The hearing has been delayed pending the submission by the California ISO and the California Power Exchange of data for the purpose of developing the factual basis needed to implement the refund methodology and order refunds. The FERC Administrative Law Judge presiding over this hearing recently announced that this information must be submitted not later than December 7, 2001, and the deadline for completion of the hearing is March 8, 2002. While it is not possible to predict the amount of any refunds until the hearings take place, based upon the information available at this time, the Company does not believe that this proceeding will result in a material adverse effect on the Company's financial position or results of operations.
Other Subsequent Events
On October 2, 2001, the Company announced that Moody's Investors Service upgraded the Company's corporate and credit and senior unsecured notes rating to Baa3, which is investment grade rating, from Ba1. Moody's downgraded the Company's corporate credit and senior unsecured note rating to Ba1 on December 14, 2001. Fitch lowered the Company's senior unsecured debt rating to BB+ on December 19, 2001.
On October 16, 2001, the Company acquired California Energy General Corporation and CE Newburry, Inc. from MidAmerican Energy Holdings Company for an undisclosed amount. The transaction includes the companies' geothermal resource assets, contracts, leases and development opportunities associated with the Glass Mountain Known Geothermal Resource Area ("Glass Mountain KGRA") located in Siskiyou County, California, approximately 30 miles south of the Oregon border. These purchases are directly related to the Company's plans to develop the 49.5-megawatt Fourmile Hill Geothermal Project located in the Glass Mountain KGRA.
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The Fourmile Hill project is in advanced development and is projected to be online by late 2004. Power from the project is committed to the Bonneville Power Administration ("BPA") under a 20-year contract and will be delivered within BPA's northern California service territory.
On October 16, 2001, the Company completed offerings of $530 million in aggregate principal amount of 8.500% Senior Notes Due 2008 issued by Calpine Canada Energy Finance ULC and guaranteed by the Company (a reopening of senior notes previously issued in April 2001), and $850 million in aggregate principal amount of 8.500% Senior Notes Due 2011 issued by the Company directly (a reopening of senior notes previously issued in February 2001).
On October 18, 2001, the Company completed an offering of C$200 million in aggregate principal amount of 8.750% Senior Notes Due 2007 issued by its wholly owned subsidiary Calpine Canada Energy Finance ULC and guaranteed by the Company, and completed offerings of L200 million in aggregate principal amount of 8.875% Senior Notes Due 2011 and E175 million in aggregate principal amount of 8.375% Senior Notes Due 2008 issued by its wholly owned subsidiary Calpine Canada Energy Finance II ULC and guaranteed by the Company. Proceeds from the offerings will be used to refinance existing bridge loan financings incurred to fund recently completed transactions, finance the development and construction of additional power generation facilities and for working capital and general corporate purposes.
On October 18, 2001, the Company completed sale/leaseback transactions for the Southpoint, Broad River and RockGen facilities raising $800.0 million in sale/leaseback proceeds. In connection with these transactions, Calpine Corporation provided a guarantee for the obligations under the leases. The lessors issued lessor notes with an aggregate principal amount of $654.5 million, which was funded by the proceeds from the issuance of pass through certificates. In effect, the pass through certificates evidence the debt component of these sale/leaseback transactions. The pass through certificates were issued in two tranches: the first, consisting of $454.5 million in aggregate principal amount of 8.4% Series A Certificates due May 30, 2012, and the second, consisting of $200 million in aggregate principal amount of 9.825% Series B Certificates due May 30, 2019. Proceeds from the sale/leasebacks will be used to refinance outstanding borrowings under the Company's construction loan facilities, certain project-specific debt and other indebtedness, and for working capital and general corporate purposes.
October 22, 2001, the Company acquired the remaining 14% of the voting stock of Michael Petroleum Corporation for approximately $41.9 million.
On November 5, 2001, the Company acquired Highland Energy Company from Entergy Power Gas Operations Corporation and Louis Morrison III for an undisclosed amount.
On November 6, 2001, the Company acquired Bechtel Enterprises Holdings, Inc.'s 50% interest in the Delta Energy Center, the Metcalf Energy Center and the Russell City Energy Center for approximately $154 million and the assumption of approximately $141 million of debt.
On December 2, 2001, Enron Corp., a significant customer, filed for bankruptcy (See Note 11).
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Except for historical financial information contained herein, the matters discussed in this quarterly report may be considered "forward-looking" statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, including statements regarding the intent, belief or current expectations of Calpine Corporation (the "Company") and its management. You are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties that could materially affect actual results such as, but not limited to, (i) the timing and extent of deregulation of energy markets and the rules and regulations adopted on a transitional basis with respect thereto, (ii) the timing and extent of changes in commodity prices for energy, particularly natural gas and electricity, (iii) commercial operations of new plants that may be delayed or prevented because of various development and construction risks, such as a failure to obtain financing and the necessary permits to operate or the failure of third-party contractors to perform their contractual obligations, (iv) unseasonable weather patterns that reduce demand for power, (v) systemic economic slowdowns, which can adversely affect consumption of power by businesses and consumers, (vi) cost estimates are preliminary and actual costs may be higher than estimated, (vii) a competitor's development of lower-cost generating gas-fired power plant, (viii) risks associated with marketing and selling power from power plants in the newly-competitive energy market, (ix) risks associated with engineering, designing, manufacturing and marketing combustion turbine parts and components,
(x) delivery and performance risks associated with combustion turbine parts and components attributable to production, quality control, suppliers and transportation or (x) the successful exploitation of an oil or
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gas resource that ultimately depends upon the geology of the resource, the total amount and cost to develop recoverable reserves, and operational factors relating to the extraction of natural gas. You are also cautioned that the California energy market remains uncertain. The Company's management is working closely with a number of parties to resolve the current uncertainty. This is an ongoing process and therefore, the outcome cannot be predicted. It is possible that any such outcome will include changes in government regulations, business and contractual relationships or other factors that could materially affect the Company, however, the Company believes that a final resolution of the situation in the California energy market will not have a material adverse impact on the Company. You are also referred to the other risks identified from time to time in the Company's reports and registration statements filed with the Securities and Exchange Commission.
Selected Operating Information
Set forth below is certain selected operating information for our power plants and steam fields, for which results are consolidated in our statements of operations. Results vary for the three and nine months ended September 30, 2001, respectively, as compared to the same periods in 2000, primarily due to the consolidation of acquisitions and increased production. The results for the nine months ended September 30, 2001, as compared to the same period in 2000, benefited from favorable energy pricing. Electricity revenue is composed of fixed capacity payments, which are not related to production, and variable energy payments, which are related to production. Capacity revenue includes, besides traditional capacity payments, other revenues such as reliability must run and ancillary service revenues. The information set forth under thermal and other revenue consists of host thermal sales and other revenue (revenues in thousands.

                                             THREE MONTHS ENDED                    NINE MONTHS ENDED
                                                SEPTEMBER 30,                         SEPTEMBER 30,
                                       ------------------------------        ------------------------------
                                           2001               2000               2001               2000
                                       -----------        -----------        -----------        -----------
Adjusted electricity and
steam ("E&S") revenues:
   Energy (1) .................        $   754,674        $   400,448        $ 1,561,227        $   725,777
   Capacity ...................        $   179,482        $   154,893        $   424,805        $   299,694
   Thermal and other ..........        $    43,339        $    34,383        $   117,544        $    69,079
   Megawatt hours generated ...         13,687,401          7,049,078         28,804,105         16,108,267
   All-in electricity price per
   megawatt hour generated ....        $     71.42        $     83.66        $     73.03        $     67.95	

(1) Adjusted to include spread on sales of purchased power (See Note 10).
Megawatt hours produced at the power plants increased 94% and 79% for the three and nine months ended September 30, 2001, respectively, as compared to the same periods in 2000. This was primarily due to the addition of power plants that were either acquired or commenced commercial operation subsequent to September 30, 2000.
Results of Operations
Set forth below is a table summarizing the dollar amounts and percentages of our total revenue for the three and nine month periods ended September 30, 2001 and 2000 that represent purchased power and purchased gas sales and the costs we incurred to purchase the power and gas that we resold during these periods (in thousands, except for percentage data):

                                             THREE MONTHS ENDED                    NINE MONTHS ENDED
                                                SEPTEMBER 30,                         SEPTEMBER 30,
                                       ------------------------------        ------------------------------
                                           2001               2000               2001               2000
                                       -----------        -----------        -----------        -----------
Total revenue ..................        $2,916,105         $  744,814         $5,868,729         $1,447,168
Sales of purchased power .......         2,028,280             55,525          3,165,078             96,646
As a percentage of total revenue              69.6%               7.5%              53.9%               6.7%
Sale of purchased gas ..........            56,917              9,985            412,782             26,316
As a percentage of total revenue               2.0%               1.3%               7.0%               1.8%
Total cost of revenue ("COR") ..         2,380,214            418,555          4,753,045            903,126
Purchased power expense ........         1,764,531             54,058          2,876,119             96,910
As a percentage of total COR ...              74.1%              12.9%              60.5%              10.7%
Purchased gas expense ..........            52,856              9,423            389,814             24,642
As a percentage of total COR ...               2.2%               2.3%               8.2%               2.7%	

The primary reasons for the significant increase in these sales and cost of revenue activities in 2001 as compared with 2000 are: (a) the growth of Calpine Energy Services ("CES") in 2001 as compared with 2000 and the corresponding increase in hedging, balancing and optimization activities; (b) particularly volatile markets and high prices for electricity and natural gas, which prompted us to
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frequently adjust our hedge positions by buying power and gas and reselling it;
(c) the accounting requirements under SAB 101 and EITF 99-19, which require us to show most of our hedging contracts on a gross basis (as opposed to netting sales and cost of revenue); and (d) rules in effect throughout 2001 associated with the NEPOOL market in New England, which require that all power generated in NEPOOL be sold directly to the Independent System Operator ("ISO") in that market; we then buy from the ISO to serve our customer contracts. Generally accepted accounting principles require us to account for this activity, which applies to three of our merchant generating facilities, as the aggregate of two distinct sales and one purchase. This treatment increases revenues but not gross profit.
Three Months Ended September 30, 2001, Compared to Three Months Ended September 30, 2000
Revenue -- Total revenue increased to $2,916.1 million for the three months ended September 30, 2001, compared to $744.8 million for the same period in 2000.
Electric generation and marketing revenue increased to $2,755.6 million in 2001 compared to $643.8 million in 2000. Approximately $125.5 million of the $2,111.8 million variance was due to electricity and steam sales, which increased due to our growing portfolio. Our revenue for the period ended September 30, 2001, includes the consolidated results of additional facilities that we acquired or completed construction on subsequent to September 30, 2000. Our power marketing revenue (sales of purchased power) grew by $1,972.8 million due to increased price hedging and optimization activity as a result of the growth of our subsidiary, Calpine Energy Services, LP ("CES"), and our operating plant portfolio during the three months ended September 30, 2001. We also recognized $13.6 million in mark to market gains on power derivatives. This gain resulted from entering into an undesignated derivative contract in a market area where we do not have generating assets and therefore the contract was neither a hedge nor a normal purchase or sale. Our expansion plans may result in our entry into new markets within the next few years, which could present similar opportunities, and any resulting power and gas contracts will require similar accounting treatment.
Oil and gas production and marketing revenue increased to $139.4 million in 2001 compared to $92.9 million in 2000. The increase is due to a $46.9 million increase in marketing activities relating to purchased gas sold to third parties in hedging, balancing and related transactions.
Other revenue increased to $14.3 million in 2001 compared to $1.0 million in 2000. This increase is due primarily to $4.0 million recognized in 2001 from our custom turbine parts manufacturing subsidiary, Power Systems Mfg., LLC ("PSM"), which was acquired in December 2000, $2.6 million in interest income on loans to power projects, and $4.6 million in commissioning services related to our Delta Energy Center ("Delta") joint venture.
Cost of revenue -- Cost of revenue increased to $2,380.2 million in 2001 compared to $418.6 million in 2000. Approximately $1,710.5 million of the $1,961.6 million increase relates to the cost of power purchased by our energy services organization. Similarly, oil and gas production and marketing expense grew by $41.1 million, largely due to $52.9 million of expense for the cost of gas purchased by our energy services organization, compared to $9.4 million in the third quarter of 2000, this was offset by a $2.4 million decrease in oil and gas production expense. Fuel expense increased 74%, from $185.6 million in 2000 to $322.1 million in 2001, due to a 94% increase in megawatt hours generated and increased fuel prices. Depreciation expense increased by 55%, from $59.1 million in the third quarter of 2000 to $91.5 million in the third quarter of 2001, due to additional power facilities in consolidated operations at September 30, 2001 as compared to the same period in 2000, and due to $10.4 million in higher depreciation and depletion in our oil and gas operating subsidiaries.
Project development expense -- Project development expense decreased 20% due to several projects moving from early to late stage development during the three months ended September 30, 2001.
General and administrative expense -- General and administrative expense increased 6% to $29.9 million for the three months ended September 30, 2001, as compared to $28.1 million for the same period in 2000. The increase was attributable to continued growth in personnel and associated overhead costs necessary to support the overall growth in our operations and due to recent acquisitions, including power facilities and natural gas operations. This was offset by a decrease in cash bonus accruals to reflect a higher mix of stock options in the Company's incentive program for management.
Interest expense -- Interest expense increased 71% to $49.7 million for the three months ended September 30, 2001, from $29.1 million for the same period in 2000. Interest expense increased primarily due to the issuances of $250.0 million of Senior Notes Due 2005 in August 2000, $750.0 million of Senior Notes Due 2010 in August 2000, $1.15 billion of Senior Notes Due 2011 in February
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2001 and $1.5 billion of Calpine Canada Energy Finance ULC Senior Notes Due 2008 in April 2001. The associated incremental interest expense was partially offset by interest capitalized in connection with our growing construction portfolio.
Distributions on trust preferred securities -- Distributions on trust preferred securities increased 21% to $15.4 million for the three months ended September 30, 2001, compared to $12.7 million for the corresponding months in 2000. The increase is attributable to a full period of distributions in 2001 on the August 2000 offering.
Interest income -- Interest income increased to $21.1 million for the three months ended September 30, 2001, compared to $15.9 million for the same period in 2000. This increase is due to interest income on the PG&E receivable.
Other income (expense) -- Other income (expense) increased to $7.9 million in 2001 from $(1.2) million in 2000 primarily due to contingent income as the result of the sale of the Bayonne Power Plant and a gain on the sale of the Cessford property in Canada.
Provision for income taxes -- The effective income tax rate was approximately 31.0% and 40.2% for the three months ended September 30, 2001 and 2000, respectively. The decrease in rates was due to a year to date true-up in accordance with APB Opinion No. 28 to reflect our expansion into Canada and the United Kingdom and our cross border financings, which reduced our statutory tax rates.
Extraordinary charge, net -- The $1.2 million charge in 2000 represents the write-off of deferred financing costs related to the repayment of bridge financing and the Bank One, Texas, N.A. borrowing base facilities.
Nine Months Ended September 30, 2001, Compared to Nine Months Ended September 30, 2000
Revenue -- Total revenue increased to $5,868.7 million for the nine months ended September 30, 2001, compared to $1,447.2 million for the same period in 2000.
Electric generation and marketing revenue increased to $5,063.0 million in 2001 compared to $1,191.5 million in 2000. Approximately $719.8 million of the $3,871.5 million variance was due to electricity and steam sales, which increased due to our growing portfolio and favorable energy pricing. Our revenue for the period ended September 30, 2001, includes the consolidated results of additional facilities that we acquired or completed construction on subsequent to September 30, 2000. Our power marketing activities contributed an additional $3,068.4 million due to increased price hedging and optimization activity as a result of the growth of CES and our operating plant portfolio during the nine months ended September 30, 2001. We also recognized $83.3 million in mark to market gains on power derivatives. Almost all of this gain resulted from entering into undesignated derivative contracts where we do not have generating assets and therefore such contracts were neither hedges nor normal purchases or sales. The majority of the gain ($68.5 million) was recognized in the second quarter of 2001 from entering into a fixed-price firm-quantity power sales contract for 2002 - 2006 with one counterparty in a market area where we will not have generating assets for at least the first six months of the contract. The contract presented us with an opportunity to establish a commercial relationship with an important customer in a market where we will eventually have generation assets, and we determined there was substantial benefit in executing the agreement for the entire term requested by the counterparty as opportunities to enter into such contract may be available infrequently. Because of the structure of the contract, under SFAS No. 133 the contract and the related commodity derivative transactions did not constitute a hedge or a normal purchase or sale. Before taking into account time value of money considerations, the aggregate gain was $79.9 million. At September 30, 2001, this gain was locked in as a result of entering into offsetting fixed-price power purchases. However, on December 10, 2001, we terminated the portion of those offsetting purchases where Enron was the counterparty, which constituted approximately 30% of the power purchases. We are currently in the process of replacing these contracts, and accordingly during this period, we are exposed to changes in prices. Prior to December 31, 2001, we realized a gain of approximately $1.4 million on a pretax basis in connection with this exposure. At December 31, 2001, we had replaced approximately 19% of liquidated volume.
Oil and gas production and marketing revenue increased to $768.3 million in 2001 compared to $229.5 million in 2000. Approximately $386.5 million of the increase is due to marketing activities relating to purchased gas sold to third parties in hedging, balancing and related transactions. Additionally, approximately $152.3 million of the variance relates to increased production and commodity prices in sales to third parties from reserves acquired in Canada and the United States.
Income from unconsolidated investments in power projects decreased to $9.0 million in 2001 compared to $21.8 million during 2000. The variance is primarily due to the contractual reduction in distributions from the Sumas Power Plant of approximately $12.3 million.
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Other revenue increased to $28.4 million in 2001 compared to $4.4 million in 2000. This increase is due primarily to $10.4 million recognized in 2001 from PSM, $5.9 million in commissioning services related to Delta and a $5.4 million increase in interest income on loans to power projects.
Cost of revenue -- Cost of revenue increased to $4,753.0 million in 2001 compared to $903.1 million in 2000. Approximately $2,779.2 million of the $3,849.9 million increase relates to the cost of power purchased by our energy services organization. Similarly, oil and gas production and marketing expense grew by $384.1 million, largely due to a $365.2 million increase in expense for the cost of gas purchased and resold by our energy services organization. Fuel expense increased 122%, from $363.3 million in 2000 to $807.5 million in 2001, due to a 79% increase in megawatt hours generated and a significant increase in fuel price. Depreciation expense increased by 52%, from $154.9 million in the first nine months of 2000 to $235.7 million in the first nine months of 2001, due to additional power facilities in operation in 2001 and due to $40.6 million in higher depreciation and depletion in our oil and gas operating subsidiaries. Operating lease expense increased by $36.9 million due to leases entered into or acquired in connection with our Pasadena, Tiverton, Rumford, KIAC, West Ford Flat and Bear Canyon facilities during and subsequent to the period ended September 30, 2000.
Project development expense -- Project development expense increased 67% due to an increase of projects in the early stage of development.
General and administrative expense -- General and administrative expense increased 103% to $116.5 million for the nine months ended September 30, 2001, as compared to $57.3 million for the same period in 2000. The increase was attributable to continued growth in personnel and associated overhead costs necessary to support the overall growth in our operations and due to recent acquisitions, including power facilities and natural gas operations. This increase was offset by a decrease in cash bonus accruals to reflect a higher mix of stock options in the Company's incentive program for management.
Merger Expense -- We incurred approximately $41.6 million of expense in the nine months ended September 30, 2001, in connection with the merger with Encal Energy Ltd. on April 19, 2001. The transaction was accounted for under the pooling-of-interests method and, accordingly, all transaction costs have been expensed as incurred and all periods presented have been restated to reflect the transaction.
Interest expense -- Interest expense increased 64% to $113.0 million for the nine months ended September 30, 2001, from $69.0 million for the same period in 2000. Interest expense increased primarily due to the issuances of $250.0 million of Senior Notes Due 2005 in August 2000, $750.0 million of Senior Notes Due 2010 in August 2000, $1.15 billion of Senior Notes Due 2011 in February 2001 and $1.5 billion of Energy Finance Senior Notes Due 2008 in April 2000. The associated incremental interest expense was partially offset by interest capitalized in connection with our growing construction portfolio.
Distributions on trust preferred securities -- Distributions on trust preferred securities increased 60% to $45.9 million for the first nine months in 2001 compared to $28.7 million for the corresponding months in 2000. The increase is attributable to the issuance of additional trust preferred securities in August 2000, as well as a full period of distributions in 2001 on the January 2000 offering and the subsequent exercise of the initial purchasers' option to purchase additional securities.
Interest income -- Interest income increased to $61.0 million for the nine months ended September 30, 2001, compared to $29.1 million for the same period in 2000. This increase is due primarily to the significantly higher cash balances that we have maintained as a result of our senior notes and convertible securities offerings during the first and second quarters of 2001. This increase is also due to interest income on the PG&E receivable.
Other income (expense) -- Other income (expense) increased to $16.9 million in 2001 from $(1.4) million in 2000 primarily due to a gain on the sale of our interests in the Elwood development project, the Cessford property in Canada and the Bayonne Power Plant including related contingent income recognized as earned thereafter.
Provision for income taxes -- The effective income tax rate was approximately 35.6% and 40.4% for the nine months ended September 30, 2001 and 2000, respectively. The decrease in rates was due to a year to date true-up in accordance with APB Opinion No. 28 to reflect our expansion into Canada and the United Kingdom and our cross border financings, which reduced our statutory tax rates.
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Extraordinary charge, net -- The $1.3 million charge in 2001 was a result of writing off unamortized deferred financing costs related to the repayment of $105.0 million 9 1/4% Senior Notes Due 2004. The $1.2 million charge in 2000 represents the write-off of deferred financing costs related to the repayment of bridge financing and the Bank One, Texas, N.A. borrowing base facilities.
Cumulative effect of a change in accounting principle -- The $1.0 million of additional income, net of tax, is due to the adoption in 2001 of Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities," amended by SFAS No. 137 and SFAS No. 138 ("SFAS No. 133").
Selected Balance Sheet Information
Unconsolidated Investments in Power Projects -- Although our preference is to own 100% of the power plants we acquire or develop, there are situations when we take less than 100% ownership. Reasons why we may take less than a 100% interest in a power plant may include, but are not limited to: (a) our acquisitions of other IPP's such as Cogeneration Corporation of America in 1999 and SkyGen Energy LLC in 2000 in which minority interest projects were included in the portfolio of assets owned by the acquired entities (Grays Ferry Power Plant (40% now owned by Calpine) and Androscoggin Energy Center (32.3% now owned by Calpine) respectively); (b) opportunities to co-invest with non-regulated subsidiaries of regulated electric utilities, which under the Public Utility Regulatory Policies Act of 1978, as amended are restricted to 50% ownership of cogeneration qualifying facilities -- such as our investment in Gordonsville Power Plant (50% owned by Calpine and 50% owned by Edison Mission Energy, which is wholly-owned by Edison International Company); and (c) opportunities to invest in merchant power projects with partners who bring marketing, funding, permitting or other resources that add value to a project. An example of this is Acadia Energy Center, which is under construction in Louisiana (50% owned by Calpine and 50% owned by Cleco Midstream Resources, an affiliate of Cleco Corporation). None of our equity investment projects have nominal carrying values as a result of material recurring losses. Further, there is no history of impairment in any of these investments.
Accumulated other comprehensive loss -- Accumulated other comprehensive loss at September 30, 2001 was $223.2 million. This represents the sum of our unrealized Other Comprehensive Income ("OCI") activity for the nine month period ending September 30, 2001 of $200.1 million and the ending OCI balance at December 31, 2000 of $23.1 million.
Accumulated other comprehensive loss includes the following components: (i) unrealized pre-tax gains/losses, net of reclassification-to-earnings adjustments, from effective cash flow hedges as designated pursuant to SFAS 133 (See Note 8 - "Derivative Instruments" in the Notes to the Consolidated Condensed Financial Statements included herein); (ii) unrealized pre-tax gains/losses that result from the translation of foreign subsidiaries' balance sheets from the foreign functional currency (primarily Cdn.$) to our consolidated reporting currency (U.S.$); and (iii) the taxes associated with the unrealized gains/losses from items (i) and (ii). See Note 9 - "Comprehensive Income" in the Notes to the Consolidated Condensed Financial Statements included herein for further information.
Liquidity and Capital Resources
General -- To date, we have obtained cash from our operations; borrowings under our credit facilities and other working capital lines; sales of debt, equity, trust preferred securities and convertible debentures; operating leases, including from sale-leaseback transactions and proceeds from project financing. We have utilized this cash to fund our operations, service debt obligations, fund acquisitions, develop and construct power generation facilities, finance capital expenditures and meet our other cash and liquidity needs.
Our business is capital intensive. We are dependent on the availability of capital on attractive terms. Our strategy is also to reinvest our cash from operations into our business development and construction program.
Following a comprehensive review of our power plant development program, we recently announced the adoption of a revised capital expenditure program, which contemplates the completion of 27 power projects (representing 15,200 MW) currently under construction during 2002 and 2003. Construction of an additional 34 advanced-stage development projects (representing 15,100 MW) will be placed on hold following completion of advanced development activities pending further review, reducing previously forecasted 2002 capital spending by as much as $2 billion. Construction of these advanced stage development projects is expected to proceed when there is an established marked need for additional generating resources at prices that will allow us to meet our established investment criteria, and when capital is available to us on attractive terms. However, our development and construction program is flexible and subject to continuing review and revision based upon such criteria.
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Notwithstanding recent uncertainties in the domestic energy and capital markets, we have raised substantial capital. In the last quarter of 2001 and early 2002, we have raised nearly $5 billion of capital, including $2.6 billion in sale/leaseback transactions and senior notes issued in the U.S., Canada, the U.K. and other European markets (representing an increase in size from the $2.0 billion that we had initially sought to raise), $1.2 billion in convertible senior notes in a private placement in the U.S. (representing an increase in size from the $500 million that we had initially sought to raise), and an additional $1 billion unsecured working capital credit facility, which was recently announced and is expected to close in the first quarter of 2002.
We believe the following factors are important in assessing our ability to continue to fund our growth in the capital markets: (a) our debt-to-capital ratio; (b) various interest coverage ratios; (c) our credit and debt ratings by the rating agencies; (d) the trading prices of our senior notes in the capital markets; (e) the price of our common stock on the New York Stock Exchange; (f) our anticipated capital requirements over the coming quarters and years; (g) the profitability of our operations; (h) our cash balances and remaining capacity under existing revolving credit construction and general purpose facilities; (i) compliance with covenants in existing debt facilities; (j) actual progress in raising new or replacement capital; and (k) the stability of future contractual cash flows. We believe that our ability to complete the financing transactions described above in difficult conditions affecting the market, and our sector, in general demonstrate our ability to have access to the capital markets in the future, although availability of capital has tightened significantly throughout the power generation industry in the first quarter of 2002.
Negative working capital at September 30, 2001 -- At September 30, 2001, we had $873 million of negative working capital. The primary reasons for this were: (a) classification of the $1 billion in aggregate principal amount of our Zero-Coupon Convertible Debentures due 2021 ("Zero Coupons") as a current liability due to the one year put feature contained in these securities (this put is exercisable on April 30, 2002 and, based on the low price of our common stock compared to the conversion price, we concluded at that time that exercise of the put was highly probable); and (b) reclassification of $265.6 million in pre-bankruptcy petition PG&E receivables to non-current assets from current assets because of the assessment at that time that it was not likely that we would recover those receivables from PG&E within one year.
From December 2001 through February 2002 we repurchased $314.5 million in aggregate principal of the Zero Coupons in the market. We also issued in separate closings in December 2001 and January 2002 $1.2 billion in aggregate principal amount of Convertible Senior Notes due 2006. Proceeds from this offering will be used to retire the Zero Coupons that remain outstanding, either in open-market purchases, negotiated transactions or upon exercise by holders of the April 2002 put option described above. In December 2001, the bankruptcy court approved an agreement between Calpine and PG&E whereby PG&E will repay the $265.6 million in past due pre-petition receivables plus accrued interest thereon beginning on December 31, 2001 and with monthly payments thereafter over the next 11 months. Shortly following receipt of this bankruptcy court approval and the first payments from PG&E on December 31, 2001, we sold the remaining PG&E receivables to a third party at a $9.0 million discount. These subsequent events are expected to return our working capital at December 31, 2001 to a positive amount.
Letter of credit facility -- In August 2001, we entered into a $300 million Master Reimbursement Agreement for Letters of Credit with Credit Suisse First Boston. This facility, which was used to provide credit support to CES in connection with its trading operations, expired pursuant to its terms on December 31, 2001, and we replaced the credit support that it had provided with direct cash deposits. Inclusive of this facility, we had approximately $730.8 million in letters of credit outstanding under various credit support facilities, of which $393.5 million related to CES risk management activities. The remainder related to other operational and construction activities.
CES margin deposits -- As of September 30, 2001, CES had deposited $173.3 million in cash as margin deposits with third parties related to its business activities.
Outlook
Our strategy is to continue our rapid growth by capitalizing on the significant opportunities in the power industry, primarily through our active development and acquisition programs. In pursuing our proven growth strategy, we utilize our extensive management and technical expertise to implement a fully integrated approach to the acquisition, development and operation of power generation facilities. This approach combines our expertise in design, engineering, procurement, finance, construction management, fuel and resource acquisition, operations, risk management and power marketing, to provide us with a competitive advantage. The key elements of our strategy are as follows:
Development of new and expansion of existing power plants -- We are actively pursuing the development of new and expansion of both baseload and peaking capacity at our existing highly efficient, low-cost, gas-fired power plants that replace old and inefficient generating facilities and meet the demand for new generation. Our strategy is to develop power plants in strategic geographic locations that enable us to leverage existing power generation assets and operate the power plants as integrated electric generation systems. This
30
allows us to achieve significant operating synergies and efficiencies in fuel procurement, power marketing and operation and maintenance.
At November 12, 2001, we had 30 projects under construction, representing an additional 17,065 megawatts of net capacity. Included in these 30 projects are 4 project expansions, representing 734 megawatts of net capacity. We have also announced plans to develop 31 additional power generation projects, representing a net capacity of 17,569 megawatts. Included in these 31 development projects are 6 expansion projects representing 592 megawatts.
Acquisition of power plants -- Our strategy is to acquire power generating facilities that meet our stringent acquisition criteria and provide significant potential for revenue, cash flow and earnings growth, and that provide the opportunity to enhance the operating efficiencies of the plants. We have significantly expanded and diversified our project portfolio through numerous acquisitions of power generation facilities.
Enhance the performance and efficiency of existing power projects -- We continually seek to maximize the power generation potential of our operating assets and minimize our operation and maintenance expense and fuel cost. This will become even more significant as our portfolio of power generation facilities expands to 87 power plants with a net capacity of 28,150 megawatts, after completion of our projects currently under construction. We focus on operating our plants as an integrated system of power generation, which enables us to minimize costs and maximize operating efficiencies. We believe that achieving and maintaining a low cost of production will be increasingly important to compete effectively in the power generation industry.
Overview
The Company is engaged in the development, acquisition, ownership, and operation of power generation facilities and the sale of electricity and steam in the United States, Canada and the United Kingdom. At November 12, 2001, we had interests in 61 operating power plants representing 11,085 megawatts of net capacity.
ACQUISITIONS

DATE           DESCRIPTION                                           SELLER                          PRICE
----           -----------                                           ------                          -----
8/1/01         Announced agreement to purchase remaining 50%         Edison Mission Energy           $35 million
               equity interest in Gordonsville Power Plant

8/15/01        Acquired 86% of the voting stock of Michael           Shareholders of Michael         $273.6 million and
               Petroleum Corporation                                 Petroleum Corporation           assumption of
                                                                                                     $54.5 million of debt

8/24/01        Acquired the 1,200-megawatt Saltend Energy Centre     Entergy Corporation             US$814.4 million
                                                                                                     (at exchange rates at the
                                                                                                     closing of the acquisition)

9/12/01        Acquired remaining 33.3% interests in Hog Bayou       Intergen                        $9.6 million
               and Pine Bluff Energy Centers                         (North America), Inc.

9/20/01        Acquired 100% interest in the 250-megawatt Island     Westcoast Energy Inc.           US$212.1 million
               Cogeneration facility and 50% interest in the                                         (at exchange rates at the
               50-megawatt Whitby Cogeneration facility                                              closing of the acquisition)

10/16/01       Acquired California Energy General Corporation        MidAmerican Energy              undisclosed amount
               and CE Newburry, Inc.                                 Holdings Company

10/22/01       Acquired the remaining 14% of the voting stock        Shareholders of Michael         $41.9 million
               of Michael Petroleum Corporation                      Petroleum Corporation

11/5/01        Acquired Highland Energy Company                      Entergy Power Gas               undisclosed amount
                                                                     Operations Corporation
                                                                     and Louis Morrison III

11/6/01        Acquired remaining 50% interest in Delta              Bechtel Enterprises             Approximately
               Energy Center, Metcalf Energy Center and              Holdings, Inc.                  $154 million and the
               Russell City Energy Center                                                            assumption of approximately
                                                                                                     $141 million of debt	

31
 
FINANCE
Offerings of Senior Notes:

DATE             OFFERING                     RATE                     DUE                ISSUER
----             --------                     ----                     ---                ------
10/16/01         US $530 million              8.500%                   2008               Calpine Canada Energy Finance ULC
10/16/01         US $850 million              8.500%                   2011               Calpine Corporation
10/18/01         C$200 million                8.750%                   2007               Calpine Canada Energy Finance ULC
10/18/01         L200 million                 8.875%                   2011               Calpine Canada Energy Finance II ULC
10/18/01         E175 million                 8.375%                   2008               Calpine Canada Energy Finance II ULC	

Sale/Leaseback Transactions:

DATE                           PROCEEDS                                FACILITY
----                           --------                                --------
10/18/01                       $800.0 million                          South Point Energy Center, Broad River
                                                                       Energy Center and RockGen Energy Center	

Other:

DATE                  DESCRIPTION
----                  -----------
9/28/01               Announced the amendment of certain provisions of the Stockholder Rights Agreement
10/2/01               Moody's Investors Service upgraded corporate credit and senior unsecured notes of Calpine to Baa3 from Ba1
12/14/01              Moody's Investors Service downgraded corporate credit and senior unsecured notes of Calpine to Ba1 from
                      Baa3
12/19/01              Fitch downgraded senior unsecured debt rating of Calpine to BB+	

POWER PLANT DEVELOPMENT AND CONSTRUCTION

DATE           PROJECT                                                            DESCRIPTION
----           -------                                                            -----------
7/2/01         Sutter Energy Center                                               Announced commercial operation
7/9/01         Los Medanos Energy Center                                          Announced initial operation
7/10/01        500-megawatt Otay Mesa Generating Project located in San           Acquired from the PG&E National Energy Group
               Diego County, California

7/11/01        600-megawatt Russell City Energy Center located in Hayward,        Application for Certification ("AFC") met the
               California                                                         California Energy Commission's ("CEC")
                                                                                  data adequacy requirements; approved for
                                                                                  expedited review
7/11/01        180-megawatt Los Esteros Critical Energy Facility located in       Announced plans for development
               San Jose, California

7/11/01        Hog Bayou Energy Center                                            Announced commercial operation
7/16/01        Aries Power Project                                                Announced simple-cycle operation
7/17/01        900-megawatt Sherry Energy Center located in Wood County,          Announced plans for development
               Wisconsin

7/30/01        Channel Energy Center                                              Announced simple-cycle operation
8/24/01        540-megawatt Wawayanda Energy center located in the town of        Announced filing of Article X Application
               Wawayanda, New York

9/5/01         Broad River Energy Center                                          Announced commercial operation of 350-megawatt
                                                                                  expansion
9/24/01        Pine Bluff Energy Center                                           Announced commercial operation
9/24/01        Metcalf Energy Center                                              CEC voted unanimously to approve the
                                                                                  construction and operation
10/16/01       49.5-megawatt Fourmile Hill Geothermal Project in the Glass        Announced plans for development
               Mountain Known Geothermal Resource Area in California

11/1/01        905-megawatt Palmetto Energy Center located in South Carolina      Announced plans for development
11/1/01        1,100-megawatt Central Valley Energy Center located in             Announced filing of AFC with the CEC
               San Joaquin, California	

TURBINE PURCHASES
32

DATE OF ANNOUNCEMENT             TURBINES                         MANUFACTURER                                  DELIVERY DATES
--------------------             --------                         ------------                                  --------------
8/9/01                           27 steam turbines                Siemens Westinghouse                          2002 through 2005
8/22/01                          19 steam turbines                Toshiba International Corporation             2002 through 2005	

MANAGEMENT DEVELOPMENTS

DATE OF ANNOUNCEMENT          INDIVIDUAL                      DESCRIPTION
--------------------          ----------                      -----------
7/16/01                       Michael Polsky                  Resignation from the Board of Directors and as an officer of the
                                                              Company
7/17/01                       Gerald Greenwald                Appointment to the Board of Directors
11/5/01                       David Johnson                   Resignation as President and Chief Executive Officer of Calpine
                                                              Canada	

In accordance with SFAS No. 13 and SFAS No. 98, "Accounting for Leases" the Company's operating leases are not reflected on our balance sheet. Similarly, in accordance with APB Opinion No. 18 "The Equity Method of Accounting For Investments in Common Stock" and FASB Interpretation No. 35, "Criteria for Applying the Equity Method of Accounting for Investments in Common Stock (An Interpretation of APB Opinion No. 18)", the debt on the books of our unconsolidated equity investments is not reflected on our balance sheet. The investee debt is part of the total investee liabilities disclosed in the 2000 10-K in Note 6. The investee debt is currently estimated to be approximately $600 million. Based on our pro rata ownership share of each of the investments, our share is approximately $200 million.
We have not incurred any off-balance sheet financings since September 30, 2001 other than sale/leaseback transactions entered into in October 2001. All equity investors in these transactions are third parties that are unrelated to Calpine. The equity investees in such transactions are unrelated to Calpine and are often special-purpose entities formed by the equity investors with the sole purpose of owning a power generation facility. All equity investee debt referred to above is non-recourse to Calpine except in the case of the Aries construction debt, for which the partners, Calpine Corporation and Aquila Energy, a wholly owned subsidiary of UtiliCorp United, have provided equity support arrangements until construction is completed to cover cost overruns, if any. Calpine makes rent payments to the equity investees under these arrangements.
Enron Corp. -- On November 14, 2001, CES entered into a master netting agreement with certain Enron affiliates. On December 2, 2001, Enron Corp. and certain of its subsidiaries filed voluntary petitions for Chapter 11 reorganization with the U.S. Bankruptcy Court for the Southern District of New York. See Note 11 - "Significant Customers" in the Notes to Consolidated Condensed Financial Statements herein for further discussion of our exposure to Enron and its subsidiaries.
For the three and nine months ended September 30, 2001, $767.9 million or 26.3% and $1,329.8 million or 22.7%, of our revenue was with Enron subsidiaries, primarily Enron Power Marketing, Inc. ("EPMI") and Enron North America Corp. ("ENA"). We, primarily our subsidiary, CES, purchases significant amounts of fuel and power from ENA and EPMI, giving rise to current accounts payable and open contract fair value positions. For the three months ended September 30, 2001, CES had fuel and power purchases from ENA and EPMI of $905.3 million. For the nine months ended September 30, 2001, CES had fuel and power purchases from ENA and EPMI of $1,358.7 million. These purchases must be included in an overall understanding of our Enron exposure. The sales to and purchases from various Enron subsidiaries are mostly hedging, balancing and related and optimization transactions, and in most cases the purchases and sales are not related and should not be netted to try to gauge the profitability of transactions with Enron subsidiaries.
ENA is the parent corporation of EPMI. Enron is the direct or indirect parent corporation of ENA. In assessing our exposure to Enron subsidiaries and affiliates, we analyze our accounts receivable and accounts payable balances on contracts that have already settled and also the fair value (mark to market value) of the contracts that have not settled. In the event of a default by one or more of the Enron subsidiaries and affiliates, we might terminate some or all of the open contracts, in which case we would have an exposure to realize the fair value of the positive ("in the money") contracts. In managing the overall credit exposure to each other, Calpine and Enron have entered into a netting agreement in which they net or offset overall mark to market exposures from all transactions between certain Enron subsidiaries and CES to liabilities between those entities.
See Footnote 11 for our accounts receivable (payable) balances as well as the fair value of our open contracts with Enron subsidiaries and affiliates at November 29, 2001. We have one gas contract with Citrus Trading Corporation to purchase gas from Citrus. Our credit department has had conversations with El Paso in which El Paso affirmed their commitment to continue all deliveries of gas to Citrus. As further assurance, El Paso also stated that they have the first option to purchase the remaining 50% of Citrus Trading Corporation from Enron in the event Enron chooses to sell their share of Citrus Trading Corporation. Currently, Citrus has continued to deliver all gas as required under the contract. Our Auburndale entity is the beneficiary of a guarantee by El Paso of 50% of Citrus' payment obligations under the Citrus fuel supply contract with Auburndale.
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Based upon the foregoing, the Company has determined that a loss due to any credit exposure to Enron and its affiliates is not probable and therefore has not established a reserve relating thereto.
Our treasury department includes a credit group focused on monitoring and managing counterparty risk. The credit group monitors the net exposure with each counterparty on a daily basis. The analysis is performed on a mark to market basis using the forward curves audited by our Risk Controls group. The net exposure is compared against a counterparty credit risk threshold which is determined based on the counterparty's credit ratings, evaluation of the financial statements and bond values. The credit department monitors these thresholds to determine the need for additional collateral or an adjustment to activity with the counterparty.
We will continue to evaluate the Enron risk in the same manner as discussed above. We will adjust our threshold for Enron exposure based on factors discussed above and continue to monitor the exposure on a daily basis. We do not expect any material change in our earnings and operations if Enron is unable to continue as a supplier and customer. Our transactions with Enron were at market based pricing and we expect to continue to transact on similar terms with other counterparties. The capital market response to Enron's situation has impacted the entire industry's credit capacity to transact. It is hard to assess the long term impact of this on earnings, but, as an asset based company, we have the option and flexibility to increase our direct dealings with load serving entities, if we experience a reduced primary demand for electricity.
California Power Market -- The deregulation of the California power market has produced significant unanticipated results in the past year and a half. The deregulation froze the rates that utilities can charge their retail and business customers in California, until recent rate increases approved by the California Public Utilities Commission ("CPUC"), and prohibited the utilities from buying power on a forward basis, while wholesale power prices were not subjected to limits.
In the past year and a half, a series of factors have reduced the supply of power to California, which has resulted in wholesale power prices that for a period from mid 2000 to spring 2001 were significantly higher than historical levels. Several factors contributed to this increase. These included:
- significantly increased volatility in prices and supplies of natural gas;
- an unusually dry fall and winter in the Pacific Northwest during 2000, which reduced the amount of available hydroelectric power from that region (typically, California imports a portion of its power from this source);
- the large number of power generating facilities in California nearing the end of their useful lives, resulting in increased downtime (either for repairs or because they have exhausted their air pollution credits and replacement credits have become too costly to acquire on the secondary market); and
- continued obstacles to new power plant construction in California, which deprived the market of new power sources that could have, in part, ameliorated the adverse effects of the foregoing factors.
As a result of this situation, two major California utilities that were subject to the retail rate freeze, including PG&E, have faced wholesale prices that far exceeded the retail prices they were permitted to charge. This led to significant under-recovery of costs by these utilities. As a consequence, these utilities defaulted under a variety of contractual obligations, including payment obligations to power generators. PG&E has defaulted on payment obligations to the Company under its long-term QF contracts, which are subject to federal regulation under the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"). The PG&E QF contracts are in place at eleven of our facilities and represent nearly 600 megawatts of electricity for Northern California customers.
PG&E Bankruptcy Proceedings -- On April 6, 2001, PG&E filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. As of April 6, 2001, we had recorded approximately $265.6 million in accounts receivable with PG&E under our QF contracts, plus $68.7 million in notes receivable not yet due and payable. As of September 30, 2001, we had recorded $292.1 million in accounts receivable (the pre-petition amount of $265.6 and associated $6.0 million in interest income are classified as a long-term receivable) and $105.6 million in notes receivable not yet due and payable. We are currently selling power to PG&E pursuant to our long-term QF contracts, and PG&E is paying on a current basis for these purchases since its bankruptcy filing. With respect to the receivables recorded under these contracts, we announced on July 6, 2001, that we had entered into a binding agreement with PG&E to modify all of our QF contracts with PG&E and that, based upon such modification, PG&E had agreed to assume all of the QF contracts. Under the terms of this agreement, we will continue to receive our contractual capacity payments under the QF contracts, plus a five-year fixed energy price component that averages 5.37 cents per kilowatt-hour in lieu of the short run avoided cost. In addition, all past due receivables under the QF contracts will be elevated to administrative priority status in the PG&E bankruptcy proceeding and will be paid to the Company, with interest, upon the effective date of a confirmed plan of reorganization. Administrative claims enjoy priority over payments made to the general unsecured creditors in bankruptcy. The bankruptcy court approved the agreement on July 12, 2001. On September 20, 2001, PG&E filed its proposed plan of reorganization with the bankruptcy court. This plan is consistent with the agreement between the Company and PG&E described above. We cannot predict
34
when the bankruptcy court will confirm a plan of reorganization for PG&E, but anticipate that it will be at least twelve months following September 30, 2001.
CPUC Proceedings Regarding QF Contract Pricing -- Our QF contracts with PG&E provide that the CPUC has the authority to determine the appropriate utility "avoided cost" to be used to set energy payments for certain QF contracts, including those for all of our QF plants in California which sell power to PG&E.
Section 390 of the California Public Utility Code provides QFs the option to elect to receive energy payments based on the California Power Exchange ("PX") market clearing price. In mid-2000, our QF facilities elected this option and were paid based upon the PX zonal day ahead clearing price ("PX Price") from summer 2000 until January 19, 2001, when the PX ceased operating a day ahead market. Since that time, the CPUC has ordered that the price to be paid for energy deliveries by QFs electing the PX Price shall be based on a natural gas cost-based "transition formula." The CPUC has conducted proceedings (R.99-11-022) to determine whether the PX Price was the appropriate price for the energy component upon which to base payments to QFs which had elected the PX-based pricing option. The CPUC has issued a proposed decision to the effect that the PX price was the appropriate price for energy payments under the California Public Utility Code. However, a final decision has not been issued to date. Therefore, it is possible that the CPUC could order a payment adjustment based on a different energy price determination. We believe that the PX Price was the appropriate price for energy payments but there can be no assurance that this will be the outcome of the CPUC proceedings.
On March 28, 2001, the CPUC issued an order (Decision 01-03-067) (the "March 2001 Decision") proposing to change, on a prospective basis, the composition of the short run avoided cost ("SRAC") energy price formula, which is reset monthly, used by the California utilities in QF contracts. Prior to the March 2001 Decision, CPUC regulations calculated SRAC based on 50% Topock and 50% Malin border gas indices. In the March 2001 Decision, the CPUC changed this formulation to eliminate the prices at Topock from the SRAC formula. The March 2001 Decision is subject to challenges at the CPUC and the Federal Energy Regulatory Commission ("FERC").
On June 14, 2001, however, the CPUC issued an order (Decision 01-06-015) (the "June 2001 Decision") that authorized the California utilities, including PG&E, to amend QF contracts to elect a fixed energy price component that averages 5.37 cents per kilowatt-hour for a five-year term under those contracts in lieu of using the SRAC energy price formula. By this order, the CPUC authorized the QF contract energy price amendments without further CPUC concurrence. As part of the agreement we entered into with PG&E pursuant to which PG&E, in bankruptcy, agreed to assume its QF contracts with us, PG&E agreed with us to amend these contracts to adopt the fixed price component, that averages 5.37 cents pursuant to the June 2001 Decision. This election became effective as of July 16, 2001. As a result of the June 2001 Decision and our agreement with PG&E to amend the QF contracts to adopt the fixed price energy component, the energy price component in our QF contracts is now fixed for five years and we are no longer subject to any uncertainty that may have existed with respect to this component of our QF contract pricing as a result of the March 2001 Decision. Further, the March 2001 Decision has no bearing on PG&E's agreement with us to assume the QF contracts in bankruptcy or on the amount of the receivable that was so assumed. As such, we have not reserved our PG&E receivables.
California Long-Term Supply Contracts -- California has adopted legislation permitting it to issue long-term revenue bonds to provide funding for wholesale purchases of power. The bonds will be repaid with the proceeds of payments by retail customers over time. The California Department of Water Resources ("DWR") sought bids for long-term power supply contracts in a publicly announced auction. Calpine successfully bid in that auction and signed several long-term power supply contracts with DWR.
On February 7, 2001, we announced the signing of a 10-year, $4.6 billion fixed-price contract with DWR to provide electricity to the State of California. We committed to sell up to 1,000 megawatts of electricity, with initial deliveries of 200 megawatts starting October 1, 2001, which increases to 1,000 megawatts by January 1, 2004. The electricity will be sold directly to DWR on a 24 hours-a-day, 7 days-a-week basis.
On February 28, 2001, we announced the signing of two long-term power sales contracts with DWR. Under the terms of the first contract, a 10-year, $5.2 billion fixed-price contract, we committed to sell up to 1,000 megawatts of generation. Initial deliveries began July 1, 2001, with 200 megawatts and increase to 1,000 megawatts by as early as July 2002. Under the terms of the second contract, a 20-year contract totaling up to $3.1 billion, we will supply DWR with up to 495 megawatts of peaking generation, beginning with 90 megawatts as early as August 2001, and increasing up to 495 megawatts as early as August 2002.
FERC Investigation into California Wholesale Markets -- On June 19, 2001, FERC ordered price mitigation in 11 states in the western United States in an attempt to reduce the dependence of the California market on spot markets in favor of longer-term committed energy supplies. The order provides for price mitigation in the spot market throughout the 11 state western region during "reserve deficiency hours," which is when operating reserves in California fall below seven percent. This price will be a single market
35
clearing price based upon the marginal operating cost of the last unit dispatched by the California ISO. In addition, FERC implemented price mitigation in non-reserve deficiency hours, which will be set at 85% of the market clearing price during the last reserve deficiency period. These price mitigation procedures went into effect on June 20, 2001, and will remain in effect until September 30, 2002.
The retention by FERC of a market-based, rather than a cost-of-service-based, rate structure, will enable us to continue to realize benefits from our efficient, modern power plants. We believe that Calpine's marginal costs will continue to be below any price cap imposed by FERC, whether during reserve deficiency hours or at other times. Therefore, we believe that FERC's mitigation plan will not have a material adverse effect on Calpine's financial condition or results of operations.
FERC also ordered all sellers and buyers in wholesale power markets administered by the California ISO, as well as representatives of the State of California, to participate in a settlement conference before a FERC administrative judge. The settlement discussions were intended to resolve all issues that remain outstanding to resolve past accounts, including sellers' claims for unpaid invoices, and buyers' claims for refunds of alleged overcharges, for past periods. The settlement discussions began on June 25, 2001, and ended on July 9, 2001. The Chief Administrative Law Judge issued his report and recommendations to FERC on July 12, 2001. On July 25, 2001, FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California. The hearing has been delayed pending the submission by the California ISO and the PX of data for the purpose of developing the factual basis needed to implement the refund methodology and order refunds. The FERC Administrative Law Judge presiding over this hearing recently announced that this information must be submitted not later than December 7, 2001, and the deadline for completion of the hearing is March 8, 2002. While it is not possible to predict the amount of any refunds until the hearings take place, based upon the information available at this time, we do not believe that this proceeding will result in a material adverse effect on the Company's financial condition or results of operations.
Risk Factors
Enron Corporation -- In 2001 the Company, primarily through our CES subsidiary, has transacted a significant volume of business with units of Enron Corp. ("Enron"). Most of these transactions are contracts for sales and purchases of power and gas for hedging and optimization purposes, some of which extend out as far as 2009. In October and November of 2001, Enron announced a series of developments including restatement of the last four years of earnings, an investigation by the Securities and Exchange Commission relating to the adequacy of Enron's disclosures of certain off-balance sheet financial transactions or structures and dismissals of certain members of senior management. On December 2, 2001, Enron Corp. and certain of its subsidiaries filed voluntary petitions for Chapter 11 reorganization with the U.S. Bankruptcy Court for the Southern District of New York.
For the three and nine months ended September 30, 2001, $767.9 million or 26.3% and $1,329.8 million or 22.7% of our revenue was with Enron subsidiaries, primarily Enron Power Marketing, Inc. ("EPMI") and Enron North America Corp ("ENA"). We, primarily our subsidiary, CES, purchases significant amounts of fuel and power from ENA and EPMI, giving rise to current accounts payable and open contract fair value positions. For the three months ended September 30, 2001, CES had fuel and power purchases from ENA and EPMI of $905.3 million. For the nine months ended September 30, 2001, CES had fuel and power purchases from ENA and EPMI of $1,358.7 million. These purchases must be included in an overall understanding of our Enron exposure. The sales to and purchases from various Enron subsidiaries are mostly hedging and optimization transactions, and in most cases the purchases and sales are not related and should not be netted to try to gauge the profitability of transactions with Enron subsidiaries.
ENA is the parent corporation of EPMI. Enron is the direct or indirect parent corporation of ENA. In assessing our exposure to Enron subsidiaries and affiliates, we analyze our accounts receivable and accounts payable balances on contracts that have already settled and also the fair value (mark to market value) of the contracts that have not settled. In the event of a default by one or more of the Enron subsidiaries and affiliates, we might terminate some or all of the open contracts, in which case we would have an exposure to realize the fair value of the positive ("in the money") contracts. In managing the overall credit exposure to each other, Calpine and Enron have entered into a netting agreement in which they net or offset overall mark to market exposures from all transactions between certain Enron subsidiaries and CES to liabilities between those entities.
See Footnote 11 for our accounts receivable (payable) balances as well as the fair value of our open contracts with Enron subsidiaries and affiliates at November 29, 2001. We had no net exposure at November 29, 2001. Additionally, our Enron exposure is mitigated as we have open positions with Citrus Trading Corp., which is 50% owned by El Paso Corporation. As such, a reserve is not needed.
Our treasury department includes a credit group focused on monitoring and managing counterparty risk. The credit group monitors the net exposure with each counterparty on a daily basis. The analysis is performed on a mark to market basis using the forward curves audited by our Risk Controls group. The net exposure is compared against a counterparty credit risk threshold which is determined based on the counterparty's credit ratings, evaluation of the financial statements and bond values. The credit department monitors these thresholds to determine the need for additional collateral or an adjustment to activity with the counterparty.
We will continue to evaluate the Enron risk in the same manner as discussed above. We will adjust our threshold for Enron exposure based on factors discussed above and continue to monitor the exposure on a daily basis.
CPUC Proceedings Regarding QF Contract Pricing -- Our QF contracts with PG&E provide that the CPUC has the authority to determine the appropriate utility "avoided cost" to be used to set energy payments for certain QF contracts, including those for all of our QF plants in California which sell power to PG&E.
Section 390 of the California Public Utility Code provides QFs the option to elect to receive energy payments based on the PX market clearing price. In mid 2000, our QF facilities elected this option and were paid based upon the PX Price from summer 2000 until January 19, 2001, when the PX ceased operating a day ahead market. Since that time, the CPUC has ordered that the price to be paid for energy deliveries by QFs electing the PX Price shall be based on a natural gas cost-based "transition formula." The CPUC has conducted proceedings (R.99-11-022) to determine whether the PX Price was the appropriate price for the energy component upon which to base payments to QFs which had elected the PX-based pricing option. The CPUC has issued a proposed decision to the effect that the PX price was the appropriate price for energy payments under the California Public Utility Code. However, a final decision has not been issued to date. Therefore, it is possible that the CPUC could order a payment adjustment based on a different energy price determination. We believe that the PX Price was the appropriate price for energy payments but there can be no assurance that this will be the outcome of the CPUC proceedings.
On March 28, 2001, the CPUC issued an order (Decision 01-03-067) (the "March 2001 Decision") proposing to change, on a prospective basis, the composition of the short run avoided cost ("SRAC") energy price formula, which is reset monthly, used by the California utilities in QF contracts. Prior to the March 2001 Decision, CPUC regulations calculated SRAC based on 50% Topock and 50% Malin border gas indices. In the March 2001 Decision, the CPUC changed this formulation to eliminate the prices at Topock from the SRAC formula. The March 2001 Decision is subject to challenges at the CPUC and the FERC.
On June 14, 2001, however, the CPUC issued an order (Decision 01-06-015) (the "June 2001 Decision") that authorized the California utilities, including PG&E, to amend QF contracts to elect a fixed energy price component that averages 5.37 cents per kilowatt-hour for a five-year term under those contracts in lieu of using the SRAC energy price formula. By this order, the CPUC authorized the QF contract energy price amendments without further CPUC concurrence. As part of the agreement we entered into with PG&E pursuant to which PG&E, in bankruptcy, agreed to assume its QF contracts with us, PG&E agreed with us to amend these contracts to adopt the fixed price component that averages 5.37 cents pursuant to the June 2001 Decision. This election became effective as of July 16, 2001. As a result of the June 2001 Decision and our agreement with PG&E to amend the QF contracts to adopt the fixed price energy component, the energy price component in our QF contracts is now fixed for five years and we are no longer subject to any uncertainty that may have existed with respect to this component of our QF contract pricing as a result of the March 2001 Decision. Further, the March 2001 Decision has no bearing on PG&E's agreement with us to assume the QF contracts in bankruptcy or on the amount of the receivable that was so assumed. As such, we have not reserved our PG&E receivables.
36
FERC Investigation into California Wholesale Markets -- On June 19, 2001, FERC ordered price mitigation in 11 states in the western United States in an attempt to reduce the dependence of the California market on spot markets in favor of longer-term committed energy supplies. The order provides for price mitigation in the spot market throughout the 11-state western region during "reserve deficiency hours," which is when operating reserves in California fall below seven percent. This price will be a single market clearing price based upon the marginal operating cost of the last unit dispatched by the California ISO. In addition, FERC implemented price mitigation in non-reserve deficiency hours, which will be set at 85% of the market clearing price during the last reserve deficiency period. These price mitigation procedures went into effect on June 20, 2001, and will remain in effect until September 30, 2002.
The retention by FERC of a market-based, rather than a cost-of-service-based, rate structure, will enable us to continue to realize benefits from our efficient, modern power plants. We believe that Calpine's marginal costs will continue to be below any price cap imposed by FERC, whether during reserve deficiency hours or at other times. Therefore, we believe that FERC's mitigation plan will not have a material adverse effect on Calpine's financial condition or results of operations.
FERC also ordered all sellers and buyers in wholesale power markets administered by the California ISO, as well as representatives of the State of California, to participate in a settlement conference before a FERC administrative judge. The settlement discussions were intended to resolve all issues that remain outstanding to resolve past accounts, including sellers' claims for unpaid invoices, and buyers' claims for refunds of alleged overcharges, for past periods. The settlement discussions began on June 25, 2001, and ended on July 9, 2001. The Chief Administrative Law Judge issued his report and recommendations to FERC on July 12, 2001. On July 25, 2001, FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California. The hearing has been delayed pending the submission by the California ISO and the California Power Exchange of data for the purpose of developing the factual basis needed to implement the refund methodology and order refunds. The FERC Administrative Law Judge presiding over this hearing recently announced that this information must be submitted not later than December 7, 2001, and the deadline for completion of the hearing is March 8, 2002. While it is not possible to predict the amount of any refunds until the hearings take place, based upon the information available at this time, we do not believe that this proceeding will result in a material adverse effect on Calpine's financial condition or results of operations.
Financial Market Risks
Short-term investments -- As of September 30, 2001, we had short-term investments of $137.7 million. These short-term investments consist of highly liquid investments with maturities of less than three months. We have the ability to hold these investments to maturity, and as a result, we would not expect the value of these investments to be affected to any significant degree by the effect of a sudden change in market interest rates.
Interest rate swaps and forward interest rate agreements -- From time to time, we use interest rate swap agreements to mitigate our exposure to interest rate fluctuations. We do not use interest rate swap agreements for speculative or trading purposes. The following table summarizes the fair market value of our existing interest rate swap agreements as of September 30, 2001 (dollars in thousands):

                                               WEIGHTED
                            NOTIONAL           AVERAGE
                           PRINCIPAL           INTEREST              FAIR
MATURITY DATE                AMOUNT              RATE            MARKET VALUE
--------------            ----------           --------          ------------
2007 .........               $38,103              8.0%             $(6,216)
2007 .........                38,103              8.0               (6,199)
2007 .........                29,757              7.9               (5,025)
2007 .........                29,757              7.9               (5,009)
2008 .........               300,000              5.0               (9,446)
2008 .........               100,000              4.9               (2,943)
2008 .........                50,000              4.8               (1,094)
2009 .........                15,000              6.9               (1,593)
2011 .........                54,434              6.9               (5,683)
2011 .........               250,000              5.1               (7,634)
2012 .........               119,385              6.5              (11,743)
2014 .........                70,528              6.7               (6,969)
2015 .........                22,500              7.0               (3,225)
2018 .........                17,500              7.0               (2,692)
                          ----------              ---             --------
         Total            $1,135,067              5.8%            $(75,471)
                          ==========              ===             ========	

37
Energy price fluctuations -- As an independent power producer primarily focused on generation of electricity using gas-fired turbines, our natural physical commodity position is "short" (we require) gas and "long" (we own) power capacity. To manage forward exposure to price fluctuation in these and (to a lesser extent) other commodities, we enter into derivative commodity instruments. All transactions are subject to our risk management policy which prohibits positions that exceed production capacity and fuel requirements. Any hedging, balancing or optimization activities that we engage in are directly related to our asset-based business model of owning and operating gas-fired electric power plants. We hedge exposures that arise from the ownership and operation of power plants and related sales of electricity and purchases of natural gas, and we utilize derivatives to optimize the returns we are able to achieve from these assets for our shareholders. This model is markedly different from that of companies that engage in commodity trading operations that are unrelated to underlying physical assets. Derivative commodity instruments are accounted for under the requirements of SFAS No. 133.
The fair value of outstanding derivative commodity instruments and the change in fair value that would be expected from a ten percent adverse price change are shown in the table below (in thousands):

                                                       CHANGE IN FAIR
                                                        VALUE FROM
                                                        10% ADVERSE
                                       FAIR VALUE       PRICE CHANGE
                                       ----------      --------------
At September 30, 2001:
     Crude oil..................       $   2,688        $    (5,797)
     Electricity................         469,307            (75,340)
     Natural gas................        (592,424)          (123,930)
                                       ---------        -----------
         Total..................       $(120,429)       $  (205,067)
                                       =========        ===========	

Derivative commodity instruments included in the table are those included in Note 8 to the unaudited Consolidated Condensed Financial Statements. The fair value of derivative commodity instruments included in the table is based on present value adjusted quoted market prices of comparable contracts. During the nine months ended September 30, 2001, significant electricity price volatility occurred in the western United States. The fair value of derivative commodity instruments includes the effect of increased power prices versus our derivative forward commitments. Derivative commodity instruments offset physical positions exposed to the cash market. None of the offsetting physical positions are included in the above table.
Price changes were calculated by assuming an across-the-board ten percent adverse price change regardless of term or historical relationship between the contract price of an instrument and the underlying commodity price. In the event of an actual ten percent change in prompt month prices, the fair value of Calpine's derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices.
The primary factors affecting the fair value of the Company's derivatives at any point in time are (1) the volume of open derivative positions (MMBtu and Mwh), and (2) changing commodity market prices, principally for electricity and natural gas. The total volume of open gas derivative positions increased 29% from June 30, 2001 to September 30, 2001, while the total volume of open power derivative positions increased 175% for the same period. In that prices for electricity and natural gas are among the most volatile of all commodity prices, there may be material changes in the fair value of the Company's derivatives over time, driven both by price volatility and the increases in volume of open derivative transactions. Under SFAS No. 133, the change since the last balance sheet date in the total value of the derivatives (both assets and liabilities) is reflected either in OCI, net of tax, or in the statement of operations as an item (gain or loss) of current earnings. As of September 30, 2001, the majority of the balance in accumulated OCI represented the unrealized net loss associated with commodity cash flow hedging transactions. As noted above, there is a substantial amount of volatility inherent in accounting for the fair value of these derivatives, and the Company's results during 2001 have reflected this. See Note 8 for additional information on derivative activity and also the Form 8-K filed on September 5, 2001 for a further discussion of the Company's accounting policies related to derivative accounting. This treatment depends upon whether the derivative is designated as a cash flow or fair value hedge or whether the derivative is not designated in a hedge relationship. The following accounting applies:
- Changes in the value of derivatives designated as cash flow hedges, net of any ineffectiveness, are recorded to OCI.
- Changes in the value of derivatives designated as fair value hedges are recorded in the statement of operations with the offsetting change in value of the hedge item also recorded in the statement of operations. Any difference between these two entries to the statement of operations represents hedge ineffectiveness.
- The change in value of derivatives not designated in hedge relationships is recorded to the statement of operations.
38
 
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.
See "Financial Market Risks" in ITEM 2.
PART II - OTHER INFORMATION
ITEM 1. Legal Proceedings.
Litigation -- An action was filed against Lockport Energy Associates, L.P. and the New York Public Service Commission ("NYPSC") in August 1997 by New York State Electricity and Gas Company ("NYSEG") in the Federal District Court for the Northern District of New York. NYSEG requested the Court to direct NYPSC and FERC to modify contract rates to be paid to the Lockport Power Plant. In October 1997, NYPSC filed a cross-claim alleging that the FERC violated the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"), and the Federal Power Act by failing to reform the NYSEG contract that was previously approved by the NYPSC. On September 29, 2000, the New York Federal District Court dismissed NYSEG's complaint and NYPSC's cross-claim. The Court stated that FERC has no authority to alter or waive its regulations or exemptions to alter the terms of the applicable power purchase agreements and that Qualifying Facilities are entitled to the benefit of their bargain, even if at the expense of NYSEG and its ratepayers. NYSEG has filed an appeal with respect to this decision. In any event, the Company retains the right to require The Brooklyn Union Gas Company to purchase its interest in the Lockport Power Plant for $18.9 million, less equity distributions received by the Company, at any time before December 19, 2001. On October 5, 2001, the United States Court of Appeals affirmed the judgment of the federal district court and dismissed all of the claims raised by NYSEG against Lockport.
The Company is involved in various other claims and legal actions arising out of the normal course of business. The Company does not expect that the outcome of these proceedings will have a material adverse effect on the Company's financial position or results of operations.
ITEM 2. Changes in Securities and Use of Proceeds.
On April 19, 2001, Calpine closed the acquisition of all of the common shares of Encal Energy Ltd., a Calgary, Alberta-based natural gas and petroleum exploration and development company, through a stock-for-stock exchange in which Encal shareholders received, in exchange for each share of Encal common stock, .1493 shares of Calpine common equivalent shares (called "exchangeable shares") of Calpine's subsidiary, Calpine Canada Holdings Ltd. A total of 16,603,633 exchangeable shares were issued to Encal shareholders in exchange for their Encal common stock. Each exchangeable share is exchangeable for one share of Calpine common stock until April 19, 2002, at which date all remaining exchangeable shares will automatically be exchanged for shares of Calpine common stock.
The exchangeable shares and the underlying shares of Calpine common stock were issued without registration under the Securities Act of 1933 in reliance upon the exemption afforded by Section 3(a)(10) thereby. While no shares of Calpine common stock were issued to Encal shareholders as part of the closing of the acquisition on April 19, 2001, exchanges have been occurring from time to time since that date. Calpine is hereby reporting the issuance of all 16,603,633 shares of Calpine common stock underlying the exchangeable shares, although some exchangeable shares remain unconverted at this time.
ITEM 4. Submission of Matters to a Vote of Security Holders.
As previously reported, on July 16, 2001, we announced that Michael Polsky had resigned from the Board of Directors and on July 17, 2001, we announced the appointment of Gerald Greenwald to the Board of Directors.
ITEM 6. Exhibits and Reports on Form 8-K.
(a) Exhibits
The following exhibits are filed herewith unless otherwise indicated:

EXHIBIT
 NUMBER                                   DESCRIPTION
 ------                                   -----------
  *2.1         Combination Agreement, dated as of February 7, 2001, by and between
               Calpine Corporation and Encal Energy Ltd. (a)	

39

EXHIBIT
 NUMBER                                   DESCRIPTION
 ------                                   -----------
  *2.2         Amending Agreement to the Combination Agreement, dated as of March 16,
               2001, between Calpine Corporation and Encal Energy Ltd. (b)

  *2.3         Form of Plan of Arrangement Under Section 186 of the Business
               Corporations Act (Alberta) (included as Exhibit A to Exhibit 2.1)
               Involving and Affecting Encal Energy Ltd. and the Holders of its Common
               Shares and Options

  *3.1         Amended and Restated Certificate of Incorporation of Calpine
               Corporation (c)

  *3.2         Certificate of Correction of Calpine Corporation (d)

  *3.3         Certificate of Amendment of Amended and Restated Certificate of
               Incorporation of Calpine Corporation (e)

  *3.4         Certificate of Designation of Series A Participating Preferred Stock of
               Calpine Corporation (d)

  *3.5         Amended Certificate of Designation of Series A Participating Preferred
               Stock of Calpine Corporation (d)

  *3.6         Amended Certificate of Designation of Series A Participating Preferred
               Stock of Calpine Corporation (e)

  *3.7         Certificate of Designation of Special Voting Preferred Stock of Calpine
               Corporation(m)

  *3.8         Amended and Restated By-laws of Calpine Corporation (f)

  *4.1         Form of Exchangeable Share Provisions and Other Provisions to Be
               Included in the Articles of Calpine Canada Holdings Ltd. (included as
               Exhibit B to Exhibit 2.1)

  *4.2         Form of Support Agreement between Calpine Corporation and Calpine
               Canada Holdings Ltd. (included as Exhibit C to Exhibit 2.1)

  *4.3         Indenture dated as of August 10, 2000, between Calpine Corporation and
               Wilmington Trust Company, as Trustee(g)

  *4.4         First Supplemental Indenture dated as of September 28, 2000, between
               Calpine Corporation and Wilmington Trust Company, as Trustee(h)

  *4.5         Indenture dated as of April 25, 2001, between Calpine Canada Energy
               Finance ULC and Wilmington Trust Company, as Trustee (i)

  *4.6         Guarantee Agreement dated as of April 25, 2001, by Calpine Corporation
               as guarantor of debt securities of Calpine Canada Energy Finance ULC
               (j)

  *4.7         Amended and Restated Indenture dated as of October 16, 2001, between
               Calpine Canada Energy Finance ULC and Wilmington Trust Company, as
               Trustee (j)

  *4.8         First Amendment to Guarantee Agreement dated as of October 16, 2001,
               between Calpine Corporation and Wilmington Trust Company (j)

  *4.9         Indenture dated as of October 18, 2001, between Calpine Canada Energy
               Finance II ULC and Wilmington Trust Company, as Trustee (j)

  *4.10        First Supplemental Indenture dated as of October 18, 2001, between
               Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as
               Trustee (j)

  *4.11        Guarantee Agreement dated as of October 18, 2001, between Calpine
               Corporation and Wilmington Trust Company (j)

  *4.12        First Amendment to Guarantee Agreement dated as of October 18, 2001,
               between Calpine Corporation and Wilmington Trust Company (j)

  *4.13        Rights Agreement, dated as of June 5, 1997, between Calpine Corporation
               and First Chicago Trust Company of New York, as Rights Agent (k)

  *9.1         Form of Voting and Exchange Trust Agreement between Calpine
               Corporation, Calpine Canada Holdings Ltd. and CIBC Mellon Trust
               Company, as Trustee (included as Exhibit D to Exhibit 2.1)

  *10.1        Amended and Restated Credit Agreement, dated as of February 15, 2001,
               among Calpine Construction Finance Company, L.P., The Bank of Nova
               Scotia, as Administrative Agent, and the Banks party thereto (l)	

* Incorporated by reference.
(a) Incorporated by reference to Calpine Corporation's Quarterly Report on Form 10-Q dated June 30, 2001 and filed on August 14, 2001 (File No. 1-12079).
40
(b) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-56712).
(c) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3 (File No. 333-40652).
(d) Incorporated by reference to Calpine Corporation's Annual Report on Form 10-K for the year ended December 31, 2000, filed with the SEC on March 15, 2001.
(e) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3 (File No. 333-66078).
(f) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-67446).
(g) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-72583).
(h) Incorporated by reference to Calpine Corporation's Annual Report on Form 10-K dated December 31, 2000 and filed on March 15, 2001 (File No. 001-12079).
(i) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-57338).
(j) Incorporated by reference to Calpine Corporation's Current Report on Form 8-K dated October 16, 2001 and filed on November 13, 2001 (File No. 001-12079).
(k) Incorporated by reference to Calpine Corporation's Registration Statement on Form 8-A/A filed with the SEC on September 28, 2001 (File No. 001-12079).
(l) Approximately 24 pages of this exhibit have been omitted pursuant to a request for confidential treatment. The omitted language has been filed separately with the Securities and Exchange Commission.
(m) Incorporated by reference to Calpine Corporation's Quarterly Report on Form 10-Q dated March 31, 2001 and filed on May 15, 2001 (File No. 001-12079).
(b) Reports on Form 8-K
The registrant filed the following reports on Form 8-K during the quarter ended September 30, 2001:

DATE OF REPORT              DATE FILED                   ITEM REPORTED
--------------              ----------                   -------------
July 6, 2001                July 9, 2001                     5, 7
July 12, 2001               July 13, 2001                    5, 7
July 16, 2001               July 17, 2001                    5, 7
July 26, 2001               July 27, 2001                    5, 7
August 14, 2001             September 5, 2001                   5
December 31, 2000           September 10, 2001               5, 7
September 19, 2001          September 28, 2001               5, 7	

41
 
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
CALPINE CORPORATION

By:   /s/   Ann B. Curtis                               Date: February 13, 2002
      ----------------------------------------
      Ann B. Curtis
      Executive Vice President
      (Chief Financial Officer)

By:   /s/   Charles B. Clark, Jr.                       Date: February 13, 2002
      ----------------------------------------
      Charles B. Clark, Jr.
      Senior Vice President and
      Corporate Controller
      (Chief Accounting Officer)	

42
The following exhibits are filed herewith unless otherwise indicated:
EXHIBIT INDEX

EXHIBIT
NUMBER                                 DESCRIPTION
------                                 -----------
 *2.1     Combination Agreement, dated as of February 7, 2001, by and between
          Calpine Corporation and Encal Energy Ltd. (a)

 *2.2     Amending Agreement to the Combination Agreement, dated as of March 16,
          2001, between Calpine Corporation and Encal Energy Ltd. (b)

 *2.3     Form of Plan of Arrangement Under Section 186 of the Business
          Corporations Act (Alberta) (included as Exhibit A to Exhibit 2.1)
          Involving and Affecting Encal Energy Ltd. and the Holders of its Common
          Shares and Options

 *3.1     Amended and Restated Certificate of Incorporation of Calpine
          Corporation (c)

 *3.2     Certificate of Correction of Calpine Corporation (d)

 *3.3     Certificate of Amendment of Amended and Restated Certificate of
          Incorporation of Calpine Corporation (e)

 *3.4     Certificate of Designation of Series A Participating Preferred Stock of
          Calpine Corporation (d)

 *3.5     Amended Certificate of Designation of Series A Participating Preferred
          Stock of Calpine Corporation (d)

 *3.6     Amended Certificate of Designation of Series A Participating Preferred
          Stock of Calpine Corporation (e)

 *3.7     Certificate of Designation of Special Voting Preferred Stock of Calpine
          Corporation (m)

 *3.8     Amended and Restated By-laws of Calpine Corporation (f)

 *4.1     Form of Exchangeable Share Provisions and Other Provisions to Be
          Included in the Articles of Calpine Canada Holdings Ltd. (included as
          Exhibit B to Exhibit 2.1)

 *4.2     Form of Support Agreement between Calpine Corporation and Calpine
          Canada Holdings Ltd. (included as Exhibit C to Exhibit 2.1)

 *4.3     Indenture dated as of August 10, 2000, between Calpine Corporation and
          Wilmington Trust Company, as Trustee(g)

 *4.4     First Supplemental Indenture dated as of September 28, 2000, between
          Calpine Corporation and Wilmington Trust Company, as Trustee(h)

 *4.5     Indenture dated as of April 25, 2001, between Calpine Canada Energy
          Finance ULC and Wilmington Trust Company, as Trustee (i)

 *4.6     Guarantee Agreement dated as of April 25, 2001, by Calpine Corporation
          as guarantor of debt securities of Calpine Canada Energy Finance ULC
          (j)

 *4.7     Amended and Restated Indenture dated as of October 16, 2001, between
          Calpine Canada Energy Finance ULC and Wilmington Trust Company, as
          Trustee (j)

 *4.8     First Amendment to Guarantee Agreement dated as of October 16, 2001,
          between Calpine Corporation and Wilmington Trust Company (j)

 *4.9     Indenture dated as of October 18, 2001, between Calpine Canada Energy
          Finance II ULC and Wilmington Trust Company, as Trustee (j)

 *4.10    First Supplemental Indenture dated as of October 18, 2001, between
          Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as
          Trustee (j)

 *4.11    Guarantee Agreement dated as of October 18, 2001, between Calpine
          Corporation and Wilmington Trust Company (j)

 *4.12    First Amendment to Guarantee Agreement dated as of October 18, 2001,
          between Calpine Corporation and Wilmington Trust Company (j)

 *4.13    Rights Agreement, dated as of June 5, 1997, between Calpine Corporation
          and First Chicago Trust Company of New York, as Rights Agent (k)

 *9.1     Form of Voting and Exchange Trust Agreement between Calpine
          Corporation, Calpine Canada Holdings Ltd. and CIBC Mellon Trust
          Company, as Trustee (included as Exhibit D to Exhibit 2.1)

 *10.1    Amended and Restated Credit Agreement, dated as of February 15, 2001,
          among Calpine Construction Finance Company, L.P., The Bank of Nova
          Scotia, as Administrative Agent, and the Banks party thereto (l)	

43

* Incorporated by reference.
(a) Incorporated by reference to Calpine Corporation's Quarterly Report on Form 10-Q dated June 30, 2001 and filed on August 14, 2001 (File No. 1-12079).
(b) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-56712).
(c) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3 (File No. 333-40652).
(d) Incorporated by reference to Calpine Corporation's Annual Report on Form 10-K for the year ended December 31, 2000, filed with the SEC on March 15, 2001.
(e) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3 (File No. 333-66078).
(f) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-67446).
(g) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-72583).
(h) Incorporated by reference to Calpine Corporation's Annual Report on Form 10-K dated December 31, 2000 and filed on March 15, 2001 (File No. 001-12079).
(i) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-57338).
(j) Incorporated by reference to Calpine Corporation's Current Report on Form 8-K dated October 16, 2001 and filed on November 13, 2001 (File No. 001-12079).
(k) Incorporated by reference to Calpine Corporation's Registration Statement on Form 8-A/A filed with the SEC on September 28, 2001 (File No. 001-12079).
(l) Approximately 24 pages of this exhibit have been omitted pursuant to a request for confidential treatment. The omitted language has been filed separately with the Securities and Exchange Commission.
(m) Incorporated by reference to Calpine Corporation's Quarterly Report on Form 10-Q dated March 31, 2001 and filed on May 15, 2001 (File No. 001-12079).
44